diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/filing.txt b/raw/filings/0000719733/2003/0001193125-03-051450/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..7e6bf092726528d644f2524cf030060686718b05 --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/filing.txt @@ -0,0 +1,3090 @@ +10-K +1 +d10k.htm +FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 28, 2003 +Form 10-K for the Fiscal Year Ended June 28, 2003 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +Annual Report +Pursuant to Section 13 +or 15(d) of +The Securities Exchange Act of 1934 +For the Fiscal Year Ended June 28, 2003 +Commission File Number 0-11559 +KEY TRONIC CORPORATION +Washington +91-0849125 +(State of Incorporation) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan +Road +Spokane, Washington 99216 +(509) 928-8000 +Securities registered pursuant to Section 12(b) of the Act: +None +Securities registered pursuant to Section 12(g) of the Act: +Common Stock +The registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 +months, and has been subject to such filing requirements during the past 90 days. +Indicate by checkmark if delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information +statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. +Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange +Act). Yes ¨ No x . +The aggregate market value of the voting stock held by non-affiliates of the +Registrant was $10,470,911 as of December 28, 2002. +The number +of shares of Common Stock of the Registrant outstanding as of August 29, 2003 was 9,672,580 shares. +The Exhibit Index is located at pages 38 - 39. +DOCUMENTS INCORPORATED BY REFERENCE +The following documents are incorporated by reference to the extent specified herein: +Document Description +Proxy Statement dated September 19, 2003 +10-K Part III +Table of Contents +KEY TRONIC CORPORATION +2003 FORM 10-K +TABLE OF CONTENTS +Page +Part I +Item 1. +Business +3-6 +Item 2. +Properties +6-7 +Item 3. +Legal Proceedings +7 +Item 4. +Submission of Matters to a Vote of Security Holders +7 +Part II +Item 5. +Market for the Registrant’s Common Stock and Related Stockholder Matters +8 +Item 6. +Selected Financial Data +8 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +9-16 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +16 +Item 8. +Financial Statements and Supplementary Data +17-34 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosures +34 +Item 9A +Controls and Procedures +34 +Part III +Item 10. +Directors and Executive Officers of the Registrant +35-36 +Item 11. +Executive Compensation +36 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +36-37 +Item 13. +Certain Relationships and Related Transactions +37 +Part IV +Item 15. +Exhibits, Financial Statement Schedule, Reports on Form 8-K and Signatures +38-43 +2 +Table of Contents +FORWARD-LOOKING STATEMENTS +This Annual Report contains forward-looking statements in addition to historical information. Forward-looking statements are subject to +certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in +“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, +which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to revise or publicly release the results of any revision to forward-looking statements. Readers should carefully review the risk factors +described in other documents the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q. +PART I +Item 1. +BUSINESS +Key Tronic Corporation (dba KeyTronicEMS), a Washington corporation organized in 1969, and its subsidiaries (hereinafter collectively called the “Company” or “Key Tronic” unless the context +otherwise requires) are principally engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs). The Company also manufactures keyboards for personal computers, terminals, and workstations primarily in standard +layouts that can be sold directly from inventory on hand. +BACKGROUND +Historically, Key Tronic was a manufacturer of only electronic keyboards, +but about five years ago, after assessing its strengths and capabilities, the Company’s focus was shifted to electronic manufacturing services (EMS). Presently, Key Tronic is known as an independent provider of a mix of EMS services for OEMs. +The Company’s manufacturing capabilities include tool making, precision molding, prototype design, liquid plastic injection molding, printed circuit board assembly (both through-hole and surface-mount), and full box build. +Operations are currently conducted in facilities in the United States, China, Ireland and +Mexico. This global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower transportation costs and reduced product fulfillment time. +The EMS industry is comprised of companies that provide a range of manufacturing services for +OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to external manufacturing, and it is expected to continue in this growth pattern for several years. +CUSTOMERS AND MARKETING +OEM MARKETS +The Company provides manufacturing services for outsourced OEM products. Key Tronic is capable of providing a mix of EMS services including product design, tool making, +precision molding, prototype design, liquid plastic injection molding, printed circuit board assembly, full box builds, and printing screened silver flexible circuit membranes. The percentage of revenues from EMS services for the fiscal years ended +June 28, 2003, June 29, 2002, and June 30, 2001 were 88.6%, 89.4%, and 76.2%, respectively. Sales of such products are generally not seasonal in nature. +Clorox accounted for 31% of consolidated revenue in fiscal year 2003 compared to 39% in fiscal year 2002. Hewlett Packard accounted for approximately 8%, 10%, and 39% of +the Company’s consolidated revenues in fiscal years 2003, 2002, and 2001, respectively. Lexmark accounted for 8%, 13%, and 27% of consolidated revenues in fiscal years 2003, 2002, and 2001, respectively. No other customers accounted for 10% or +more of consolidated revenues in the three fiscal years presented. In the fiscal years ended June 28, 2003, June 29, 2002, and June 30, 2001, the five largest customers, including Clorox, Hewlett Packard, and Lexmark, accounted for 63%, 76%, and 81% +of total sales, respectively. +3 +Table of Contents +Although keyboard manufacturing is still included in the Company’s product offerings, annual sales continue to +decline. During the fiscal years ended June 28, 2003, June 29, 2002, and June 30, 2001, the Company realized revenues of approximately $14.6 million, $18.3 million, and $38.6 million, respectively, from the sale of keyboards representing +approximately 11.1%, 10.4%, and 23.3% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the demand for standard products, the Company maintains a purchase-from-stock +program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original system-supplied keyboards. Keyboard sales can increase somewhat during the last +half of each calendar year in conjunction with the holiday season, but generally sales of these products are not seasonal in nature. +The Company markets its products and services primarily through its direct sales organization aided by strategically located field sales people and distributors. Although +the Company established relationships with several independent sales organizations to assist in marketing the Company’s EMS product lines in the U.S., commissions earned and paid during fiscal year 2003 were insignificant. +MANUFACTURING +Since inception, the Company has made substantial investments in developing and expanding its now extensive capital equipment base to +achieve selective vertical integration in its manufacturing processes. The Company designs and develops tooling for injection molding machines and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the +Company has invested in equipment to produce printed screened silver flexible circuit membranes. +The Company’s automated manufacturing processes enable it to work closely with its customers during design and prototype stages of production for new custom products and to jointly increase productivity and +reduce response time to the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality +and enhance turnaround time during product development. +Key Tronic uses a +variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, surface-mount technology, flexible robotic assembly, +computerized vision system quality inspection, automated switch and keytop installation, and automated functional testing. +The Company purchases materials and components for its products from many different suppliers both domestic and international. Key Tronic develops close working +relationships with its suppliers, many of whom have been supplying products to the Company for several years. +FOREIGN MARKETS +Information concerning +geographic areas for the years ended June 28, 2003, June 29, 2002, and June 30, 2001 is summarized in the following table. +(in thousands) +Domestic +Exports +U.S. +Operations +Mexico +Operations +Europe +Operations +Far East +Operations +Eliminations +Consolidated +2003 +Net sales: +Unaffiliated customers +$ +11,940 +$ +114,674 +$ +— +$ +4,280 +$ +— +$ +— +$ +130,894 +Affiliates +$ +2,248 +$ +— +$ +27,864 +$ +18 +$ +17,232 +$ +(47,362 +) +$ +— +Total +$ +14,188 +$ +114,674 +$ +27,864 +$ +4,298 +$ +17,232 +$ +(47,362 +) +$ +130,894 +Income (loss) before income taxes +$ +— +$ +11,110 +$ +2,304 +$ +(21 +) +$ +716 +$ +(100 +) +$ +14,009 +Total assets +$ +— +$ +46,439 +$ +8,533 +$ +3,134 +$ +6,806 +$ +(5,787 +) +$ +59,125 +4 +Table of Contents +(in thousands) +Domestic +Exports +U.S. +Operations +Mexico +Operations +Europe +Operations +Far East +Operations +Eliminations +Consolidated +2002 +Net sales: +Unaffiliated customers +$ +26,888 +$ +143,324 +$ +— +$ +5,291 +$ +88 +$ +— +$ +175,591 +Affiliates +$ +— +$ +3,187 +$ +40,438 +$ +(60 +) +$ +19,037 +$ +(62,602 +) +$ +— +Total +$ +26,888 +$ +146,511 +$ +40,438 +$ +5,231 +$ +19,125 +$ +(62,602 +) +$ +175,591 +Income (loss) before income taxes +$ +— +$ +(22,242 +) +$ +2,023 +$ +(885 +) +$ +948 +$ +210 +$ +(19,946 +) +Total assets +$ +— +$ +38,940 +$ +14,658 +$ +3,161 +$ +9,511 +$ +(8,831 +) +$ +57,439 +2001 +Net sales: +Unaffiliated customers +$ +77,842 +$ +76,950 +$ +— +$ +9,617 +$ +1,456 +$ +— +$ +165,865 +Affiliates +$ +— +$ +6,355 +$ +41,829 +$ +12 +$ +22,312 +$ +(70,508 +) +$ +— +Total +$ +77,842 +$ +83,305 +$ +41,829 +$ +9,629 +$ +23,768 +$ +(70,508 +) +$ +165,865 +Income (loss) before income taxes +$ +— +$ +(14,714 +) +$ +2,955 +$ +(978 +) +$ +1,865 +$ +142 +$ +(10,730 +) +Total assets +$ +— +$ +68,394 +$ +20,703 +$ +5,879 +$ +8,056 +$ +(28,661 +) +$ +74,371 +Foreign sales from worldwide +operations, including domestic exports, were $16.2 million in fiscal year 2003 compared to $32.3 million and $88.9 million in fiscal years 2002 and 2001, respectively. Foreign sales were 12.4% of net sales in fiscal 2003 compared to 18.4% and 53.6% +in fiscal years 2002 and 2001, respectively. The decrease in foreign sales for fiscal year 2003 is primarily the result of declining sales to the foreign subsidiaries of one EMS customer. Sales from Key Tronic Europe, Ltd. represented approximately +3.3% of consolidated sales to external customers in fiscal year 2003 compared to 3.0% and 5.8% in fiscal years 2002 and 2001, respectively. Although the Company hopes to expand its EMS business to include the European market, sales within Europe at +the present time are primarily for electronic keyboards. Key Tronic Computer Peripheral Co., Ltd., the Company’s subsidiary in Shanghai, China, did not have any local sales in fiscal year 2003. In fiscal years 2002 and 2001, local sales from +this subsidiary were $88,000 and $1.5 million, respectively. The decrease in sales to local Chinese customers is also the result of lower purchases from the same EMS customer as previously discussed. +For additional financial information about foreign operations, see Note 9 to the Consolidated +Financial Statements. +BACKLOG +At August 2, 2003, the Company had an order backlog of approximately $34.9 million. This +compares with a backlog of approximately $24.6 million at August 3, 2002. Order backlog is not necessarily indicative of future sales. Order backlog consists of purchase orders received for products expected to be shipped approximately within the +next fiscal year, although shipment dates are subject to change due to design modifications or other customer requirements. +RESEARCH, DEVELOPMENT, AND ENGINEERING +The Company’s research, development, and engineering expenses (RD&E) were $2.9 million, $2.6 million, and $2.7 million in fiscal years 2003, 2002, and 2001, +respectively. Research, development and engineering expenses as a percentage of sales were 2.2%, 1.5%, and 1.6% in fiscal years 2003, 2002, and 2001, respectively. The slight increase in RD&E expenses in fiscal year 2003 was due primarily to +reinstated employee wages and merit increases that were under a 10% pay reduction in fiscal year 2002, and a reduction in rebillable engineering services. +COMPETITION +The Company believes that its principal competitors in the EMS market are divided into three tiers, the first tier includes such companies as Solectron, Celestica and Flextronics. The second tier has several companies +with smaller market capitalization such as Plexus, Pemstar and Suntron. The Company believes they are positioned in the third tier, which includes SMTC, Nortech, and IEC Electronics. The principal methods of competition are price, quality, and the +range of services offered. +5 +Table of Contents +TRADEMARKS AND PATENTS +The Company owns several keyboard patents; however, since the Company’s focus is now electronic manufacturing services, management believes that these patents +will not have a significant impact on future revenues. The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets in its business. In fiscal year 2001, Key Tronic began operating under the +trade name “KeyTronicEMS” to better represent its primary business concentration. +EMPLOYEES +As of June 28, 2003, the +Company had approximately 2,687 employees compared to 1,995 on June 29, 2002. The increase in employees is due primarily to additional production workers hired in the Company’s Juarez facility to ramp-up for more labor intensive customer +programs. The Company’s employees in Ireland and Reynosa are represented by local unions. The Company has never experienced any material interruption of production due to labor disputes. +The Company’s employee benefit program includes bonus programs involving periodic +payments to all employees based on quarterly or fiscal year before-tax income. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution on a portion of the employee’s contribution, and also provides +group health, life, and disability insurance plans. The Company also maintains stock option plans for certain employees and outside directors. +Item 2. +PROPERTIES +The Company has manufacturing and sales operations located in the United States, Mexico, China, and Ireland. The table below lists the locations and square feet for the Company’s operations as of June 28, 2003: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane (1) +49,400 +Leased +Research and Administration +Spokane +96,000 +Leased +Manufacturing +Las Cruces, New Mexico +45,000 +Owned +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehousing +Total USA +270,400 +Juarez, Mexico +165,000 +Owned +Manufacturing +Juarez, Mexico +49,411 +Leased +Manufacturing and warehousing +Reynosa, Mexico +140,000 +Leased +Manufacturing +Total Mexico +354,411 +Shanghai, China (2) +63,000 +Leased +Manufacturing +Total China +63,000 +Dundalk, Ireland +3,500 +Leased +Offices +Total Ireland +3,500 +Grand Total +691,311 +(1) +On December 27, 2000, the Company sold two contiguous parcels of land and its corporate headquarters building in Spokane to Royal Hills Associates L.L.C. (RHA) for approximately $6 +million in cash. In connection with the sale, the Company entered into a 10-year lease agreement with RHA for one floor of the two-story building, which the Company continues to occupy as its headquarters. The Company’s monthly rent payment is +$30,875 plus allocated expenses. +(2) +The Company began an assembly operation in Shanghai, China in fiscal year 1999. During fiscal year 2003, the leased space was increased from 36,000 sq. ft. to 63,000 sq. ft. to +accommodate a new surface mount technology (SMT) line for automated circuit board production. +6 +Table of Contents +On February 21, 2002, the Company sold real estate, which it owned in Cheney, Washington for $1,705,628 +and recorded a gain of $84,000. +The Company considers the +productive capacity of its current facilities sufficient to carry on the Company’s business. +Item 3. +LEGAL PROCEEDINGS +On December 20, 2001, a jury in Seattle federal court rendered a verdict in the case of F&G Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic +Corporation, United States District Court for the Western District of Washington, Case No. C99-995C (the “litigation”) finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury +awarded damages to the Plaintiffs in the amount of $16.5 million. The judgment against the Company was subsequently increased to approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a +settlement of the litigation with the Plaintiffs (hereafter called “F&G”). Under the terms of the settlement, the Company has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G +of $2.5 million, as well as make quarterly payments to F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is greater, until the total payment of $7.0 million has been made, provided the total payment is completed by December +15, 2005. During fiscal year 2003, the Company made payments to F&G totaling approximately $3.3 million. +If the total of $7.0 million is not paid by 12/15/2005, the total settlement amount increases on 12/15/2005 to $7.6 million. If payment of $7.6 million is not completed by 12/15/2006 the total settlement amount +increases to $8.2 million. If payment of $8.2 million is not completed by 12/15/2007 the total settlement amount increases to $8.8 million. If payment of $8.8 million is not completed by 12/15/2008 the total settlement amount increases to $9.7 +million. If payment of $9.7 million is not completed by 12/15/2009 the total settlement amount increases to $10.6 million. If payment of $10.6 million is not made by 12/15/2010 the total settlement amount increases to $11.5 million. Any unpaid +balance remaining at 12/15/2011 will accrue interest thereafter at prime plus 1½% per annum until paid. If the Company fails to make any minimum quarterly payment when due, Plaintiffs have the right to accelerate all remaining payments in the +amount of $11.5 million less any amounts previously paid. +Reported earnings +for the year ended June 28, 2003, include a one-time benefit of $12.2 million ($1.26 per share) for reversal of previously recorded litigation accrual. +Also see Note 8 to the Consolidated Financial Statements. +Item 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None +7 +Table of Contents +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED SHAREHOLDER MATTERS +MARKET INFORMATION +Key Tronic Corporation’s common stock is traded on the NASDAQ National Market System under the symbol KTCC. Quarterly high and low closing sales prices for Key +Tronic common stock for fiscal years 2003 and 2002 were as follows: +2003 +2002 +High +Low +High +Low +First Quarter +$ +1.200 +$ +0.280 +$ +2.650 +$ +1.420 +Second Quarter +1.450 +0.300 +2.900 +1.200 +Third Quarter +1.400 +1.050 +1.570 +0.950 +Fourth Quarter +2.850 +1.050 +2.060 +0.680 +High and low stock prices are based on +the daily closing price reported by the NASDAQ National Market System. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +HOLDERS AND DIVIDENDS +As of June 28, 2003, the Company had 1,405 shareholders of record. The Company’s current financing agreement contains a covenant that +prohibits the declaration or payment of dividends (see Note 4 to Consolidated Financial Statements). The Company has never paid a cash dividend and does not anticipate payment of dividends on its Common Stock in the foreseeable future. +Item 6: +SELECTED FINANCIAL DATA +The following selected consolidated financial data of the Company should be read in conjunction with “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and the other financial information included elsewhere in this Form 10-K. +KEY TRONIC TEN-YEAR FINANCIAL HIGHLIGHTS +(Dollars in millions, +except share amounts) +Fiscal Years Ended +2003 +2002 +2001 +2000 +1999 +1998 +1997 +1996 +1995 +1994 +Net sales +$ +130.9 +$ +175.6 +$ +165.9 +$ +164.4 +$ +178.3 +$ +170.1 +$ +184.9 +$ +201.0 +$ +207.5 +$ +159.4 +Operating income (loss) +2.6 +1.2 +(9.5 +) +(3.5 +) +5.2 +1.2 +1.9 +0.2 +9.8 +(8.3 +) +Net income (loss) +13.4 +(25.4 +) +(11.4 +) +(5.3 +) +3.0 +(0.9 +) +0.3 +(1.8 +) +4.4 +(1.1 +) +Net income (loss) per share +1.39 +(2.62 +) +(1.18 +) +(.55 +) +0.32 +(0.09 +) +0.03 +(0.22 +) +0.53 +(0.13 +) +Depreciation/amortization +2.9 +4.4 +5.9 +6.3 +6.9 +9.6 +8.9 +10.0 +8.9 +8.6 +Total assets +59.1 +57.4 +74.4 +95.8 +101.0 +97.0 +100.2 +93.5 +115.1 +101.9 +Net working capital +21.8 +22.3 +22.9 +37.1 +41.8 +34.6 +38.5 +28.0 +37.7 +28.5 +Long-term liabilities +13.6 +26.8 +9.4 +17.6 +20.6 +22.9 +27.0 +17.3 +28.5 +26.6 +Shareholders’ equity +23.1 +9.7 +35.3 +46.6 +51.9 +48.8 +49.8 +49.5 +51.3 +44.5 +Book value per share +2.39 +1.00 +3.65 +4.83 +5.39 +5.06 +5.18 +5.80 +6.06 +5.38 +Cash dividends per share +0 +0 +0 +0 +0 +0 +0 +0 +0 +0 +Number of shares outstanding at year end (thousands) +9,673 +9,673 +9,673 +9,641 +9,631 +9,631 +9,611 +8,534 +8,456 +8,271 +Number of employees at year end +2,687 +1,995 +2,151 +1,926 +1,951 +2,721 +2,429 +2,824 +2,925 +2,163 +8 +Table of Contents +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +CRITICAL ACCOUNTING POLICIES +Revenue Recognition : The Company recognizes revenue primarily when products are shipped. Staff Accounting Bulletin 101 states that revenue generally is realized or +realizable and earned when all of the following criteria are met: +• +Persuasive evidence of an arrangement exists +• +Delivery has occurred or services have been rendered +• +The seller’s price to the buyer is fixed or determinable +• +Collectibility is reasonably assured +The Company believes that it meets the above criteria for the following reasons: +• +Customer purchase orders confirming the price and shipping terms are required prior to shipment. +• +The terms of the Company’s sales are generally FOB shipping point, meaning that the customer takes ownership of the goods and assumes the risk of loss when the goods leave the +Company’s premises. +• +The seller’s price to the buyer is fixed or determinable—as noted, we require a customer purchase order, which confirms the price and shipping terms. +• +Collectibility is reasonably assured—the credit terms for customers are pre-established so that collection of the account can be reasonably assured. +Inactive, Obsolete and Surplus Inventory Reserve : The Company reserves for +inventories that it deems inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that the Company produces. Demand is determined by expected sales or customer forecasts. If expected sales do not materialize, +then the Company would have inventory in excess of their reserves and would have to charge the excess against future earnings. In the case where the Company has purchased material based upon a customer’s forecast, the Company is usually covered +by lead-time assurance agreements with each customer. These contracts state that the financial liability for material purchased within lead-time and based upon the customer’s forecasts, lies with the customer. If the Company purchases material +outside the lead-time assurance agreement and the customer’s forecasts do not materialize, the Company would have the financial liability and would have to charge the excess against future earnings. +Allowance for Doubtful Accounts : The Company values its accounts receivable net of an +allowance for doubtful accounts. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future, and the amount of this allowance is disclosed in the Company’s Consolidated Balance Sheet. The +estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of +the Company’s customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, the Company could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty : An accrual is made for expected warranty costs, with +the related expense recognized in cost of good sold. Management reviews the adequacy of this accrual quarterly based on historical analysis and anticipated product returns. Over the course of the past three years, the Company’s warranty expense +has decreased. The declines in warranty expense and the related accrual account are directly related to the change in the composition of the Company’s revenue from keyboards to EMS. As the Company has made the transition from manufacturing only +keyboards to EMS, its exposure to warranty issues has declined significantly. The Company’s warranty period for keyboards is generally longer than that for EMS products. Also the Company does not warrant design defects for EMS customers. +RESULTS OF OPERATIONS +Fiscal year 2003: Fiscal year 2003 sales decreased 25% from fiscal year 2002. The +decrease is due primarily to a slowdown in shipments to some of the Company’s larger EMS customers for a variety of reasons. Keyboard sales decreased approximately $3.7 million or 19.9%. EMS sales also decreased by $41.0 million or 26%. During +fiscal years 2003 and 2002, the Company was involved in litigation that resulted in a judgment in 2002 which negatively affected the ability to acquire new business. The Company has seen an increase in new business upon the elimination of this +uncertainty in 2003 and expects this trend to continue. The Company’s gross profit percentage on sales for fiscal year 2003 was 11.4%, which is an increase of 2.9% from the previous year. The increase is a result of improvements in overall +operating efficiencies and lower material costs. +9 +Table of Contents +Fiscal year 2002: Fiscal year 2002 sales increased approximately 6% from fiscal year 2001. This increase is due +primarily to sales of new EMS products offset by declines in keyboard sales. Revenue from keyboard sales decreased $20.3 million or 52.6% from fiscal 2001 while revenue from EMS sales increased $30.7 million or 24.3%. Even though keyboard sales +continue to decline, the margins on these sales usually exceed those that can be realized on EMS sales, so the Company will continue to service this industry until such time that it is no longer feasible or profitable to do so. The Company’s +gross profit percentage on total sales for fiscal year 2002 was 8.5%, which is an increase of 3.9% from fiscal year 2001. This increase is primarily the result of a new product line in full production during fiscal year 2002 that utilized excess +operating capacity. +NET SALES +Net sales in fiscal year 2003 were $130.9 million compared to $175.6 million and $165.9 +million in fiscal years 2002 and 2001, respectively. This represents an approximate decrease of 25% in fiscal year 2003. This decrease was due to decreased shipments to some of the Company’s larger customers for a variety of reasons. A key +factor was a slowing of newly acquired customers until the legal judgment was settled in the second quarter of fiscal year 2003. Other main factors included end of life programs and poor economic conditions in general. EMS sales were 88.6% of total +revenue in fiscal 2003 compared to 89.4% and 76.2% in fiscal years 2002 and 2001, respectively. Keyboard sales were 11.1% of sales in fiscal 2003 compared to 10.4% and 23.3% of total sales in fiscal years 2002 and 2001, respectively. +COST OF SALES +In fiscal year 2003, cost of sales was 88.6% of revenues compared to 91.5% in fiscal year +2002 and 95.4% in fiscal year 2001. The decrease in 2003 was due primarily to improvements in operating efficiencies and lower material costs. The decrease in fiscal year 2002 compared to fiscal year 2001 was due primarily to an EMS customer +acquired during fiscal year 2002 that helped utilize excess capacity in the Company’s main manufacturing facility. The Company provides for warranty costs based on historical experience and anticipated product returns. The amounts charged to +expense were approximately $150,000, $215,000, and $220,000 in fiscal years 2003, 2002, and 2001, respectively. The decline in warranty expense is attributable primarily to the decline in keyboard sales. The Company’s warranty period for +keyboards is generally longer than that for EMS products. Also the Company does not warrant design defects for EMS customers. Cost of sales also includes shipping and handling costs of $2.0 million in fiscal year 2003 compared to $2.4 million in +fiscal year 2002, and $2.0 million in fiscal year 2001. The Company’s freight costs for inbound shipments of production materials fluctuate from year to year depending on negotiated freight rates and the necessity for expedited shipping +methods. The Company provides for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense were $.2 million, $2.2 million, and $.4 million in fiscal +years 2003, 2002, and 2001, respectively. +RESEARCH, +DEVELOPMENT AND ENGINEERING +The Company’s research, development +and engineering (RD&E) expenses were $2.9 million, $2.6 million, and $2.7 million, in fiscal years 2003, 2002, and 2001, respectively. As a percentage of sales, these expenses were 2.2%, 1.5%, and 1.6%, respectively. In fiscal years 2003, 2002, +and 2001, the Company focused most of its RD&E efforts on EMS programs. The slight increase in fiscal year 2003 compared to fiscal year 2002 and 2001 is due primarily to reinstated employee wages and merit increases that were previously under a +10% pay reduction and merit freeze in the prior fiscal year, and a reduction in rebillable engineering services in fiscal year 2003. +SELLING +Selling expenses were $2.3 million, $2.8 million, and $4.7 million in fiscal years 2003, 2002, and 2001, respectively. Selling expenses as a percentage of revenues were +1.7%, 1.6%, and 2.9%, respectively. The decreases in fiscal year 2003 compared to fiscal year 2002 were due primarily to a reduction in promotional programs and marketing expenses related to keyboard sales. The significant decrease in selling +expenses for fiscal year 2002 compared to fiscal year 2001 was due to a large drop in keyboard sales. Sales of keyboards through distribution require greater promotional and marketing programs than sales of EMS products. In addition, the Company did +not employ outside sales representatives for its keyboard products in fiscal year 2002, so commission expense was significantly decreased. +10 +Table of Contents +GENERAL AND ADMINISTRATIVE +General and administrative expenses were $7.2 million, $8.4 million and $9.6 million in fiscal years 2003, 2002, and 2001, respectively. As +a percentage of sales, these expenses were 5.5% in fiscal year 2003, 4.8% in fiscal year 2002, and 5.8% in fiscal year 2001. The decrease in fiscal year 2003 was primarily due to a year over year decline in legal expenses as a result of the +termination of the F&G litigation. Other contributing factors were a decreased provision for doubtful accounts, lower telephone expenses, decreased staffing in Ireland, and the adoption of SFAS 142, which ceased the amortization of goodwill. The +decrease between fiscal years 2002 and 2001 was due primarily to a significant decrease in the provision for doubtful accounts and decreased compensation and fringe benefits as a result of attrition and a 10% reduction in salaries. +INTEREST EXPENSE +The Company had interest expenses of $1.0 million, $1.3 million, and $2.1 million in fiscal +years 2003, 2002, and 2001, respectively. The decrease in fiscal year 2003 was due to a significant decrease in the Company’s interest rates applied to its revolving debt. The major factor in the interest rates was the decrease in bank prime +rates. The decrease in interest expense for fiscal year 2002 was attributable to lower rates and lower outstanding debt. +OTHER INCOME, NET +The Company had net other income of $237,000, $358,000, and $879,000 in fiscal years 2003, 2002, and 2001, respectively. Other income in fiscal year 2003 is primarily +proceeds from the sale of an equity security. The net other income for fiscal year 2002 is primarily the result of recognizing gains on the sale of two of the Company’s buildings. In February of 2002, the Company sold its real estate located in +Cheney, Washington, recognizing a gain of $84,000 (Note 3). In December of 2000, the Company sold its headquarters building in Spokane, Washington, under a sale lease-back transaction. The Company did not recognize the gain on the sale of the +headquarters building during the time period that it had guaranteed the rent on the second floor of the building. At the end of December 2001, the one-year of guaranteed rent payments was fulfilled, and the Company recognized a gain of $479,000 +(Note 3) from the sale of this building. The difference between these gains and the reported amount of $358,000 is due to miscellaneous non-operating expenses. The other income in 2001 was primarily due to gains from the sale of fixed assets. +INCOME TAXES +The Company had income tax expense of $600,000 in fiscal year 2003 compared to $5.4 million +in fiscal year 2002 and $643,000 in fiscal year 2001. The current year’s expense is primarily the result of tax provisions on the earnings of foreign subsidiaries. The large increase in income tax expense in fiscal year 2002 was due primarily +to establishing a 100% valuation allowance against the Company’s net deferred tax assets after a litigation judgment was awarded to F&G Scrolling Mouse. These assets totaled $4.5 million. Prior to the award of this judgment, Key Tronic had +almost $45.9 million in tax loss carry-forwards. Financial Accounting Standard No. 109 requires that management assess the sources of future taxable income, which may be available to recognize the deductible differences that comprise deferred tax +assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or all of the deferred tax assets will not be realized. Because the litigation judgment was considered evidence of the Company’s +possible inability to utilize the balance of the deferred tax assets, the valuation allowance was increased to the full value. The Company’s tax loss carry-forwards begin expiring in 2006. The remaining $900,000 of the Company’s income tax +provision was due to income taxes on the earnings of foreign subsidiaries. The income tax expense in fiscal year 2001 was also due to income taxes on the earnings of foreign subsidiaries. +INTERNATIONAL (MEXICO, EUROPE, ASIA) +One of the Company’s Mexican subsidiaries, Key Tronic Juarez SA de CV, owns an assembly and molding facility in Juarez, Mexico. This +subsidiary is primarily used to support the Company’s U.S. operations. The Company’s Mexican subsidiary, Key Tronic Reynosa SA de CV, leases a manufacturing facility in Reynosa, Mexico. This subsidiary is used exclusively to manufacture +products for one EMS customer. +11 +Table of Contents +Key Tronic Europe, Ltd. (KTEL), the Company’s operation in Dundalk, Ireland, is primarily used to solicit sales and +support customers within Europe. The keyboards previously manufactured in Dundalk, Ireland to support the European market are now assembled at the Shanghai, China facility. +Key Tronic Computer Peripheral Co., Ltd., located in Shanghai, China, began operations in 1999. Its primary function is manufacturing +electronic keyboards for export; however, it is also capable of providing EMS services for local customers. +Foreign sales from worldwide operations, including domestic exports, were $16.2 million in fiscal year 2003 compared to $32.3 million and $88.9 million in fiscal years 2002 and 2001, respectively. Foreign sales were +12.4% of net sales in fiscal 2003 compared to 18.4% and 53.6% in fiscal years 2002 and 2001, respectively. Sales from Key Tronic Europe, Ltd. represented approximately 3.3% of consolidated sales to external customers in fiscal year 2003 compared to +3.0% and 5.8% in fiscal years 2002 and 2001, respectively. The decrease in foreign sales for fiscal year 2003 is primarily the result of declining sales to the foreign subsidiaries of one EMS customer and the continuing decline of keyboard sales +from the Company’s subsidiary in Ireland. Although the Company hopes to expand its EMS business to include the European market, sales within Europe currently are primarily for electronic keyboards. Key Tronic Computer Peripheral Co., Ltd., the +Company’s subsidiary in Shanghai, China, did not have any sales to local customers during fiscal year 2003. In fiscal years 2002 and 2001, sales to local customers were $88,000 and $1.5 million, respectively. The decrease in sales to local +Chinese customers is also the result of lower purchases from the same EMS customer as previously discussed. +CAPITAL RESOURCES AND LIQUIDITY +The +Company used $.5 million of cash from operating activities in fiscal year 2003 versus $.9 million and $7.5 million of cash provided by operating activities in fiscal years 2002 and 2001, respectively. The cash used in fiscal year 2003 was due +primarily to a significant increase in inventory levels. The increase in inventories was from a ramp-up for new EMS programs, and from an increase in the Company’s printed circuit board business. Printed circuit board production requires higher +material content than most other EMS programs currently in production. Also contributing to the use of cash was the amount paid to F&G under the settlement agreement signed during fiscal year 2003. Offsetting the uses in cash was a reduction in +accounts receivable due to reduced sales in fiscal year 2003. The decrease in cash provided by operating activities in fiscal year 2002 compared to fiscal year 2001 was due primarily to the reduction of accounts payable. The significant increase in +cash provided by operating activities in fiscal year 2001 was due primarily to the collection of trade receivables. Capital expenditures were $2.1 million, $1.1 million, and $.7 million in fiscal years 2003, 2002, and 2001, respectively. The +increase in capital expenditures for fiscal year 2003 was primarily due to the purchase of new production equipment in the Las Cruces, New Mexico facility. The Company’s cash position decreased by $.2 million from fiscal year 2002 to fiscal +year 2003. The Company had working capital of $21.8 million at June 28, 2003 and $22.3 million at June 29, 2002. +The Company’s primary financing activity in fiscal years 2003, 2002, and 2001 was the borrowing and repayment under the Company’s debt agreements. +On August 22, 2001, the Company entered into a financing agreement with CIT Group/Business +Credit, Inc. which provides a revolving credit facility up to $25 million. The new revolving loan is secured by the assets of the Company. The interest rate provisions of the agreement specify four alternative levels of margin to be added to the +prime rate ranging from 0.25% to 1.00% depending on compliance with certain financial covenants. For the first year of the financing agreement with CIT, a margin of 0.75% was added to the prime rate. The prime rate is based on the JP Morgan Chase +prime rate. The margin applicable at June 28, 2003 was 0.50%. The full rate of interest as of June 28, 2003 was 4.50%. On November 19, 2002 a third amendment to the financing agreement was signed. The amendment contains financial covenants that +relate to total equity, earnings before interest, taxes, depreciation and amortization, and a minimum fixed charge ratio. The amendment also extended the term of the agreement by one year. The agreement became effective on August 24, 2001, and will +now terminate on August 23, 2005. As of June 28, 2003, the Company was in compliance with all loan covenants. At June 28, 2003, the outstanding revolving loan balance was $9,864,000 compared to $6,475,000 at fiscal year end June 29, 2002. The +increase in the loan balance was due primarily to required payments to F&G in compliance with the settlement of the legal judgment in the second quarter of fiscal 2003. +In addition to the Company’s revolving credit facility payment obligations and normal operating expenses, at June 28, 2003, the Company +had a $1.1 million litigation settlement payment obligation, and operating lease commitments of approximately $270,000 per month for the remainder of the 2004 fiscal year. The Company believes that funds available under the revolving credit facility +and internally generated funds can satisfy cash requirements for a period in excess of 12 months. +12 +Table of Contents +Contractual Obligations +In the normal course of business, the Company enters into contracts, which obligate the Company to make payments in the future. The table below sets forth the +Company’s significant future obligations by time period. +Payments Due by Fiscal Years +Long-Term Contractual Obligations +Total +Less Than +1 Year +1-3 Years +3-5 Years +More Than +5 Years +(in thousands) +Long-term debt +$ +9,864 +$ +— +$ +9,864 +$ +— +$ +— +Operating leases +8,640 +3,225 +3,263 +1,049 +1,103 +Litigation +3,717 +1,124 +2,593 +— +— +Total +$ +22,221 +$ +4,349 +$ +15,720 +$ +1,049 +$ +1,103 +RISKS AND UNCERTAINTIES THAT COULD +AFFECT FUTURE RESULTS +The following risks and uncertainties could affect +the Company’s actual results and could cause results to differ materially from past results or those contemplated by the Company’s forward-looking statements. When used herein, the words “expects”, “believes”, +“anticipates” and similar expressions are intended to identify forward-looking statements. +Potential Fluctuations in Quarterly Results The Company’s quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including changes in overall demand for +customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by the Company, its customers and its competitors and changes in pricing policies by the Company, its +customers, its suppliers and its competitors. For example, the Company relies on customers’ forecasts to plan its business. If those forecasts are overly optimistic, the Company’s revenues and profits may fall short of expectations. +Conversely, if those forecasts are too conservative, the Company could have an unexpected increase in revenues and profits. The products which the Company manufactures for its customers have relatively short product lifecycles, therefore the +Company’s business, operating results and financial condition are dependent in significant part on the Company’s ability to obtain orders from new customers and new product programs from existing customers. +Competition The EMS industry is intensely competitive. Competitors may offer customers +lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect the Company’s business, operating results and financial condition. +The Company’s inability to provide comparable or better manufacturing services at a lower cost than its competitors could cause sales to decline. In addition, competitors can copy the Company’s non-proprietary designs after the Company has +invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Concentration of Major Customers At present, the Company’s customer base is highly concentrated and could become even more concentrated. The Company’s +largest EMS customer accounted for 31% of net sales in fiscal year 2003. This same customer accounted for 39% of sales in 2002. Three other of the Company’s EMS customers accounted for 9%, 8%, and 8% of net sales during fiscal year 2003. These +same customers accounted for 10%, 13%, and 10% of net sales in fiscal year 2002 and 0%, 27%, and 39% in fiscal year 2001. There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at +current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more +of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +Dependence on Suppliers The Company is dependent on many suppliers, including sole +source suppliers, to provide key components and raw materials used in manufacturing customers’ products. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or +reductions in shipment of products to our customers which could adversely affect the Company’s operating results and damage customer relationships. +13 +Table of Contents +Dependence on Key Personnel The Company’s future success depends in large part on the continued service of +its key technical, marketing and management personnel and on its ability to continue to attract and retain qualified employees. The competition for such personnel is intense and there can be no assurance that the Company will be successful in +attracting and retaining such personnel. The loss of key employees could have a material adverse effect on the Company’s business, operating results and financial condition. +Foreign Manufacturing Operations Virtually all products manufactured by the Company are produced at the Company’s facilities +located in Mexico and China. Accordingly the Company’s operations are subject to a variety of risks unique to international operations including import and export duties and value added taxes, import and export regulation changes, the burden +and cost of compliance with foreign laws and foreign economic and political risk. +Technological Change and New Product Risk The markets for the Company’s customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and relatively +short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. The Company’s success will depend upon its customers’ +ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated +customer requirements. Failure of the Company’s customers to do so could substantially harm the Company’s customers’ competitive positions. There can be no assurance that the Company’s customers will be successful in identifying, +developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Dilution and Stock Price Volatility As of June 28, 2003, there were outstanding options for the purchase of approximately 2,086,000 shares of common stock of the +Company (Common Stock), of which options for approximately 1,849,000 shares were vested and exercisable. Holders of the Common Stock will suffer immediate and substantial dilution to the extent outstanding options to purchase the Common Stock are +exercised. The stock price of the Company may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to the Company such as variations in quarterly +operating results or changes in analysts’ earnings estimates, or to factors relating to the EMS and computer industries or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These +fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +NEW ACCOUNTING PRONOUNCEMENTS +In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible +Assets.” SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only approach. Under the statement, the Company records intangible assets that are acquired individually or with a group of other assets in +the financial statements at acquisition. Goodwill in each reporting unit shall be tested for impairment annually. An entity has six months from the date it initially applies Statement 142 to complete the first step of that transitional goodwill +impairment test. The Company adopted SFAS No. 142 on June 30, 2002, and completed its impairment test during the second quarter ended December 28, 2002. The test did not indicate an impairment of the Company’s stated goodwill of $765,000. +The net effect of adopting this accounting standard was to eliminate +amortization expense of $128,000 annually and increase net income by $0.01 per basic and diluted share for the fiscal year ended June 28, 2003. In accordance with SFAS No. 142, the effect of this accounting change is reflected prospectively. +Comparative disclosure as if the change had been retroactively applied to the prior years is as follows (in thousands, except per share data): +Fiscal Years Ended +June +2003 +2002 +2001 +Reported net income (loss) +$ +13,409 +$ +(25,362 +) +$ +(11,373 +) +Add back: goodwill amortization, net of tax +0 +128 +128 +Total +$ +13,409 +$ +(25,234 +) +$ +(11,245 +) +Basic and diluted earnings (loss) per share: +Reported net income (loss) +$ +1.39 +$ +(2.62 +) +$ +(1.18 +) +Goodwill amortization +0 +.01 +.02 +Adjusted basic and diluted earnings (loss) per share +$ +1.39 +$ +(2.61 +) +$ +(1.16 +) +14 +Table of Contents +In April 2002, the Financial Accounting Standards Board issued SFAS No. 145. The purpose of this statement is to rescind +previously issued SFAS No. 4, 44, and 64, and to amend SFAS No. 13. Statement No. 4 and 64 relate to reporting gains and losses from extinguishment of debt. Statement No. 44 concerned accounting for intangible assets of motor carriers, and Statement +No. 13, “Accounting for Leases” was amended to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are +similar to sale-leaseback transactions. The provisions related to Statement 13 are effective for transactions occurring after May 15, 2002, and the remaining provisions of the statement are effective for fiscal years beginning after May 15, 2002. +The Company adopted this new statement after issuance in April 2002; however, there were no lease transactions during the period between May 15, 2002 and June 29, 2002 that would be covered under the provisions of the statement. This new statement, +in its entirety, is in effect for the Company’s fiscal year beginning June 30, 2002. Adoption of this statement did not have a material impact on the Company’s consolidated financial statements. +Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated +With Exit or Disposal Activities”, was issued in June 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, +“Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)” by requiring that a liability for a cost associated with an exit or disposal +activity be recognized and measured initially at fair value only when the liability is incurred. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. The Company adopted SFAS No. +146 on June 30, 2002 for exit or disposal activities initiated after December 31, 2002. Adoption of this statement did not have a material impact on the Company’s consolidated financial statements. +In December 2002, the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation, +Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee +compensation. It also amends the disclosure provisions of SFAS No. 123 to require prominent disclosure about the effects of reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. +Finally, this Statement amends APB Opinion No. 28, Interim Financial Reporting, to require disclosure about those effects in interim financial information. The amendments to SFAS No. 123, which provides alternative methods of transition for an +entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation is effective for financial statements for fiscal years ending after December 15, 2002. The amendment to SFAS No. 123 relating to +disclosures and the amendment to Opinion 28 is effective for financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. The Company has adopted the disclosure provisions of SFAS No. 148 on its +2003 financial statements. As the Company does not intend to adopt the fair value provisions of FAS No. 123, the Company does not believe that implementing SFAS No. 148 will have a material impact on its consolidated financial statements. +In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 +on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to +as derivatives) and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”. SFAS No. 149 is effective for all contracts created or modified after June 30, 2003. The Company does +not believe that the adoption of this standard will have a material effect on its consolidated financial statements. +In November 2002, the FASB issued Interpretation (FIN) No. 45, which requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of +the obligation undertaken in issuing the guarantees. It also requires disclosure in interim and annual financial statements of its obligations under certain guarantees it has issued. The initial recognition and measurement provisions of FIN No. 45 +are to be applied prospectively to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements for periods ending after December 15, 2002. Adoption of FIN No. 45 did not have a material +effect on the Company’s consolidated financial statements. +In January +2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities”. FIN No. 46 clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements, to certain entities in which equity investors +do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. A variable interest entity is +required to be consolidated by the Company that has a majority of the exposure to expected losses of the variable interest entity. The Interpretation is effective immediately for variable interest entities created after January 31, 2003. For +variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003, the Interpretation applies in the first fiscal year or interim period beginning after June 15, 2003. The Company does not believe +the issuance of this Interpretation will have a material impact on its consolidated financial statements. +15 +Table of Contents +In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of +both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Standard requires that certain freestanding +financial instruments be classified as liabilities, including mandatorily redeemable financial instruments, obligations to repurchase the issuer’s equity shares by transferring assets and certain obligations to issue a variable number of +shares. SFAS No. 150 is effective for financial instruments entered into or modified subsequent to May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. It is to be implemented by +reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of the Statement and still existing at the beginning of the interim period of adoption. The Company does not anticipate +that the implementation of this Standard will have a material impact on its consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company’s major market risk relates to its secured debt. The +Company’s debt is secured substantially by all of the Company’s assets. The interest rates applicable to the Company’s revolving loan fluctuate with the JP Morgan Chase Bank prime rate. As of July 22, 2003, the JP Morgan Chase Bank +prime rate was 4.00%. +The Company does not enter into derivative transactions +or leveraged swap agreements. +Although the Company has international +operations, the functional currency for all active subsidiaries is the U.S. dollar. The Company imports for its own use raw materials that are used in its manufacturing operations. Substantially all of the Company’s purchases are denominated in +U.S. dollars and are paid under normal trade terms. +The table below presents +principal (or notional) amounts and related weighted average variable rates by fiscal year of maturity. The weighted average variable interest rates for fiscal years 2004 through 2006 are estimated based on implied forward rates in the yield curve +as of June 28, 2003. These forward rates have been increased by .50% based on the financing agreement with CIT. The Company’s revolving debt could increase or decrease depending upon cash needs over the period of time that the financing +agreement remains in place with CIT. The JP Morgan Chase Bank prime rate will fluctuate with the market and could go up or down depending on market conditions. The Company’s applicable margin is estimated to remain at .50% based on expected +performance over the course of the next two fiscal years. +Fiscal Years +Fair Value +June 28, 2003 +(In thousands) +2004 +2005 +2006 +Total +Interest rate risk: +Secured revolving debt +$ +9,864 +$ +9,864 +$ +9,864 +Average interest rate +4.50 +% +4.50 +% +4.50 +% +16 +Table of Contents +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Reports of Independent Certified Public Accountants +The Board of Directors and Shareholders +Key Tronic Corporation +Spokane, Washington +We have audited the accompanying consolidated balance sheet of Key Tronic Corporation and +subsidiaries (the Company) as of June 28, 2003, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended. We have also audited the schedule listed in the accompanying index. These +financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit. +We conducted our audit in accordance with auditing standards generally accepted in the United +States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements and schedule are free of material misstatement. An audit includes examining, on a test basis, +evidence supporting the amounts and disclosures in the financial statements and schedule. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of +the financial statements and schedule. We believe that our audit provides a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation and subsidiaries at June 28, 2003, and the results of +their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the schedule presents fairly, in all material respects, the information set forth therein. +As discussed in Note 1 to the consolidated financial statements, the Company changed its +method for accounting for goodwill in fiscal 2003. +/s/ BDO Seidman, LLP +August 14, 2003 +Spokane, Washington +17 +Table of Contents +To the Shareholders and Board of Directors of Key Tronic Corporation: +We have audited the accompanying consolidated balance sheet of Key Tronic Corporation and +subsidiaries (the Company) as of June 29, 2002, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years ended June 29, 2002, and June 30, 2001. These financial statements are the responsibility +of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the +audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also +includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, such consolidated financial statements present fairly, in all material +respects, the financial position of Key Tronic Corporation and subsidiaries at June 29, 2002, and the results of their operations and their cash flows for the years ended June 29, 2002, and June 30, 2001, in conformity with accounting principles +generally accepted in the United States of America. +/s/ Deloitte & Touche LLP +Deloitte & Touche LLP +Seattle, Washington +August 16, 2002 +18 +Table of Contents +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 28, 2003 +June 29, 2002 +ASSETS +Current assets: +Cash and cash equivalents +$ +956 +$ +1,205 +Trade receivables, less allowance for doubtful accounts of $105 and $444 +17,078 +20,978 +Inventories +24,151 +18,395 +Other +2,050 +2,588 +Total current assets +44,235 +43,166 +Property, plant and equipment +86,469 +85,286 +Less accumulated depreciation +74,487 +73,054 +Total property, plant and equipment +11,982 +12,232 +Other assets: +Restricted cash +1,142 +280 +Other, net of accumulated amortization of $565 and $240 +1,001 +996 +Goodwill +765 +765 +Total assets +$ +59,125 +$ +57,439 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities: +Current portion of long-term obligations +$ +730 +$ +228 +Accounts payable +13,145 +14,409 +Accrued compensation and vacation +4,213 +2,803 +Litigation judgment +1,124 +293 +Other +3,240 +3,172 +Total current liabilities +22,452 +20,905 +Long-term liabilities: +Revolving loan +9,864 +6,475 +Litigation judgment +2,593 +19,186 +Other long-term obligations +1,096 +1,162 +Total long-term liabilities +13,553 +26,823 +Commitments and contingencies (Notes 4 and 8) +Shareholders’ equity +Common stock, no par value, authorized 25,000 shares; issued and outstanding 9,673 and 9,673 shares, respectively +38,393 +38,393 +Retained deficit +(15,273 +) +(28,682 +) +Total shareholders’ equity +23,120 +9,711 +Total liabilities and shareholders’ equity +$ +59,125 +$ +57,439 +See +notes to consolidated financial statements. +19 +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS +Years Ended +(In thousands, except per share amounts) +June 28, 2003 +June 29, 2002 +June 30, 2001 +Net sales +$ +130,894 +$ +175,591 +$ +165,865 +Cost of sales +115,936 +160,606 +158,309 +Gross profit on sales +14,958 +14,985 +7,556 +Operating expenses: +Research, development and engineering +2,913 +2,554 +2,717 +Selling +2,250 +2,793 +4,724 +General and administrative +7,183 +8,414 +9,599 +Operating income (loss) +2,612 +1,224 +(9,484 +) +Interest expense +1,026 +1,314 +2,125 +Litigation (settlement) judgment expense +(12,186 +) +20,214 +— +Other income, net +(237 +) +(358 +) +(879 +) +Income (loss) before income taxes +14,009 +(19,946 +) +(10,730 +) +Income tax provision +600 +5,416 +643 +Net income (loss) +$ +13,409 +$ +(25,362 +) +$ +(11,373 +) +Income (loss) per share: +Income (loss) per common share – basic and diluted +$ +1.39 +$ +(2.62 +) +$ +(1.18 +) +Weighted average shares outstanding – basic and diluted +9,673 +9,673 +9,668 +See +notes to consolidated financial statements. +20 +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY +Common Stock +Retained +Earnings/(Deficit) +Accumulated +Other +Comprehensive +Income +Total +(In thousands) +Shares +Amount +Balances, July 1, 2000 +9,641 +$ +38,304 +$ +8,053 +$ +245 +$ +46,602 +Comprehensive income: +Net loss – 2001 +$ +(11,373 +) +$ +(11,373 +) +Exercise of stock options +32 +$ +89 +$ +89 +Balances, June 30, 2001 +9,673 +$ +38,393 +$ +(3,320 +) +$ +245 +$ +35,318 +Comprehensive income: +Net loss – 2002 +$ +(25,362 +) +$ +(25,362 +) +Other comprehensive income: +Foreign currency translation +$ +(245 +) +$ +(245 +) +Total comprehensive income +$ +(25,607 +) +Balances, June 29, 2002 +9,673 +$ +38,393 +$ +(28,682 +) +$ +— +$ +9,711 +Comprehensive income: +Net income – 2003 +$ +13,409 +$ +13,409 +Balances, June 28, 2003 +9,673 +$ +38,393 +$ +(15,273 +) +$ +— +$ +23,120 +See +notes to consolidated financial statements. +21 +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS +Years Ended +(In thousands) +June 28, 2003 +June 29, 2002 +June 30, 2001 +Increase (decrease) in cash and cash equivalents: +Cash flows from operating activities: +Net income (loss) +$ +13,409 +$ +(25,362 +) +$ +(11,373 +) +Adjustments to reconcile net income (loss) to cash provided (used) by operating activities: +Depreciation and amortization +2,938 +4,397 +5,886 +Provision for obsolete inventory +203 +2,225 +435 +Provision for (recovery of) doubtful receivables +(56 +) +175 +714 +Provision for warranty +150 +215 +220 +Litigation judgment (settlement) +(12,186 +) +19,479 +— +(Gain) loss on sale of assets +20 +(559 +) +(743 +) +Deferred income tax provision +— +12,866 +4,632 +Foreign currency translation +— +(245 +) +— +Changes in operating assets and liabilities: +Trade receivables +3,956 +521 +11,620 +Inventories +(5,959 +) +(19 +) +1,683 +Other assets +(22 +) +2,376 +2,517 +Accounts payable +(1,264 +) +(6,976 +) +(2,931 +) +Accrued compensation and vacation +1,410 +188 +312 +Changes in deferred tax assets +— +(8,350 +) +(4,632 +) +Deferred sales proceeds +— +(349 +) +(435 +) +Litigation settlement +(3,576 +) +— +— +Other liabilities +433 +337 +(424 +) +Cash provided (used) by operating activities +(544 +) +919 +7,481 +Cash flows from investing activities: +Purchase of property and equipment +(2,128 +) +(1,142 +) +(720 +) +Proceeds from sale-leaseback of real estate +— +— +4,030 +Increase in restricted cash +(862 +) +(280 +) +— +Proceeds from sale of property and equipment and assets held for sale +46 +1,711 +1,226 +Cash provided (used) by investing activities +(2,944 +) +289 +4,536 +) +Cash flows from financing activities: +Payment of financing costs +(150 +) +(504 +) +(50 +) +Proceeds from issuance of common stock +— +— +89 +Repayment of long-term debt +— +— +(3,307 +) +Borrowing under revolving credit agreement +139,000 +177,432 +176,008 +Repayment of revolving credit agreement +(135,611 +) +(179,068 +) +(183,633 +) +Cash provided (used) by financing activities +3,239 +(2,140 +) +(10,893 +) +Increase (decrease) in cash and cash equivalents +(249 +) +(932 +) +1,124 +Cash and cash equivalents, beginning of year +1,205 +2,137 +1,013 +Cash and cash equivalents, end of year +$ +956 +$ +1,205 +$ +2,137 +Supplemental cash flow information: +Interest payments +$ +763 +$ +1,340 +$ +2,110 +Income tax payments, net of refunds +$ +348 +$ +1,208 +$ +640 +Deferred sales proceeds (see Note 3) +$ +— +$ +— +$ +2,584 +See +notes to consolidated financial statements. +22 +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. +SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic +manufacturing services (EMS) for original equipment manufacturers (OEMs), and also manufactures keyboards and other input devices. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in Ireland, Mexico, and China. Intercompany balances and transactions have +been eliminated in consolidation. One of the Company’s subsidiaries, KT FSC was legally dissolved on September 5, 2001. Another one of the Company’s subsidiaries, Key Tronic Far East Pte Ltd, was legally dissolved on February 22, 2003. The +dissolution of these subsidiaries did not have a material impact on the Company’s financial statements, since the subsidiaries had been inactive for several years. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates +and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. +Significant estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, the valuation allowances on deferred tax assets, valuation of goodwill, and the provision for warranty costs. Actual +results could differ from those estimates. +Cash Equivalents +The Company considers investments with an original maturity of three months or less to be +cash equivalents. Cash equivalents are carried at cost, which approximates fair value. +As of June 28, 2003, and June 29, 2002, the Company held restricted cash of approximately $1.1 million and $.3 million, respectively. The $1.1 million includes two amounts; $495,055 is a deposit required by the state of Washington for +self-insurers that would cover the Company’s maximum calculated workers’ compensation liability in the event of default by the Company. This calculated liability was previously covered by a bond, which was secured through an insurance +company; however, when the bond matured during the second quarter of fiscal 2003, insurance companies were no longer willing to write workers’ compensation bonds. The remaining $647,014 as of June 28, 2003 and the $279,827 as of June 29, 2002 +are the amounts of funds in the Company’s bank account, which are considered restricted, because they cannot be used for any other purpose than to decrease the Company’s revolving debt. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. +Inventories increased $5.8 million from June 29, 2002 to June 28, 2003 primarily due to a ramp up of inventory to support future EMS programs. The reserve to adjust inventory to market value for obsolete and non-saleable inventories was +approximately $3,513,000 and $4,765,000 at June 28, 2003 and June 29, 2002, respectively. The decrease in the reserve is due to the final disposition of some of the Company’s obsolete inventory during fiscal year 2003. The Company provides for +obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected lives of the assets. Constructed molds and dies are +expensed as incurred if there is no future utility beyond one year. Capitalized molds and dies are depreciated over the expected useful lives of one to three years. +23 +Table of Contents +Impairment of Long-Lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment +whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. No assets were written down during the fiscal years ended +June 28, 2003, June 29, 2002, and June 30, 2001. +Deferred Loan Fees +Deferred loan fees are amortized using the interest method over the term +of the related loan agreement. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost +of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. Accrued warranty costs at June 28, 2003 and June 29, 2002, were approximately $161,000 and $294,000, respectively. +Net Sales +Sales are generally recognized when products are shipped, because that is when the customer +takes ownership of the goods and assumes risk of loss. Provisions for estimated sales returns are not significant. The Company provides for doubtful accounts receivable primarily based on specific identification. +Cost Of Sales +Cost of sales includes related shipping and handling costs. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed costs of electronic manufacturing services (EMS) as well as design and engineering costs associated +with the production of EMS programs. Such costs are charged to expense as incurred. +Income Taxes +The Company accounts for income taxes in +accordance with provisions of Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” Under the asset and liability method prescribed by SFAS No. 109, deferred income taxes are provided for temporary +differences between the financial reporting and tax bases of assets and liabilities. Deferred taxes are measured using provisions of currently enacted tax laws. Tax credits are accounted for as a reduction of income taxes in the year the credit +originates. Determination of the unrecognized deferred tax liability on foreign subsidiary undistributed earnings is not practicable. +Earnings Per Share +Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by dividing net +income (loss) by the weighted average number of common and common equivalent shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common +shares at the average market price during the period. The computation of diluted earnings per share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an antidilutive effect on earnings per +share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Ireland, Mexico and China is +the U.S. dollar. Realized foreign currency transaction gains and losses are included in general and administrative expenses. Prior to 2001, assets and liabilities of the Company’s subsidiary in Ireland had been translated to U.S. dollars at +year-end exchange rates. Revenues and expenses had been translated at average exchange rates. Translation gains and losses had been included in a separate component of shareholders’ equity. The foreign currency translation adjustment of +$245,000 as of June 30, 2001, which was included in other comprehensive income, was written off in fiscal year 2002 as a result of the disposal of the majority of the assets of the subsidiary in Ireland. +24 +Table of Contents +Fair Value of Financial Instruments +The carrying values reflected in the balance sheets at June 28, 2003 and June 29, 2002, reasonably approximate their fair value. Based on +the borrowing rates currently available to the Company for loans with similar terms and average maturities, the fair value of long-term debt is estimated to be $9.9 million and $6.5 million, respectively, as of June 28, 2003 and June 29, 2002, which +approximates the carrying values of $9,864,000 as of June 28, 2003 and $6,475,000 as of June 29, 2002. +Stock-based Compensation +The Company +accounts for its stock-based awards to employees using the intrinsic value method in accordance with Accounting Principles Board No. 25 “Accounting for Stock Issued to Employees” (APB 25). Under APB 25, compensation expense is recognized +only if the option price is less than the quoted market price of the Company’s stock at the date of the option grant. Under SFAS No. 123 “Accounting for Stock Based Compensation”, the fair value of stock-based awards to employees is +calculated through the use of option pricing models. These models require subjective assumptions, including future stock price volatility and expected time to exercise. The Company’s calculations were made using the Black-Scholes option pricing +model with the following weighted average assumptions: expected life, 60 months in 2003, 77 months in 2002, and 73 months in 2001, respectively; stock volatility, 107.96% in 2003, 83.69% in 2002, and 81.89% in 2001, respectively; risk free interest +rates, 3.11% in 2003, 3.89% in 2002, and 8.81% in 2001, respectively, and no dividends during the expected term. The weighted average fair values of options granted during fiscal years 2003, 2002, and 2001 were $1.16, $2.07, and $4.26 per share, +respectively. +For purposes of disclosure under SFAS Nos. 123 and 148, the +following is the pro forma effect of the options had they been recorded under the fair value method (no tax effect has been included because of offsetting tax valuations): +Years Ended +June 28, 2003 +June 29, 2002 +June 30, 2001 +(in thousands, except per share information) +Net income (loss), as reported +$ +13,409 +$ +(25,362 +) +$ +(11,373 +) +Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards +(387 +) +(412 +) +(714 +) +Pro forma net income (loss) +$ +13,022 +$ +(25,774 +) +$ +(12,087 +) +Earnings per share: +Basic and diluted—as reported +$ +1.39 +$ +(2.62 +) +$ +(1.18 +) +Basic and diluted—pro forma +$ +1.35 +$ +(2.66 +) +$ +(1.25 +) +New Accounting Pronouncements +In July 2001, the Financial Accounting Standards Board (FASB) issued +Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only approach. Under the statement, the +Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. Goodwill shall be tested for impairment annually. An entity has six months from the date it initially +applies Statement 142 to complete the first step of that transitional goodwill impairment test. The Company adopted SFAS No. 142 on June 30, 2002, and completed its impairment test during the second quarter ended December 28, 2002. The test did not +indicate an impairment of the Company’s stated goodwill of $765,000. +25 +Table of Contents +The net effect of adopting this accounting standard was to eliminate amortization expense of $128,000 annually and +increase net income by $0.01 per basic and diluted share for the fiscal year ended June 28, 2003. In accordance with SFAS No. 142, the effect of this accounting change is reflected prospectively. Comparative disclosure as if the change had been +retroactively applied to the prior year is as follows (no tax effect has been included because of offsetting tax valuations): +Fiscal Years Ended +June +2003 +2002 +2001 +(in thousands, except per share data) +Reported net income (loss) +$ +13,409 +$ +(25,362 +) +$ +(11,373 +) +Add back: goodwill amortization +0 +128 +128 +Total +$ +13,409 +$ +(25,234 +) +$ +(11,245 +) +Basic and diluted earnings (loss) per share: +Reported net income (loss) +$ +1.39 +$ +(2.62 +) +$ +(1.18 +) +Goodwill amortization +0 +.01 +.02 +Adjusted basic and diluted earnings (loss) per share +$ +1.39 +$ +(2.61 +) +$ +(1.16 +) +In April, 2002, the Financial +Accounting Standards Board issued SFAS No. 145. The purpose of this statement is to rescind previously issued SFAS No. 4, 44, and 64, and to amend SFAS No. 13. Statement No. 4 and 64 relate to reporting gains and losses from extinguishment of debt. +Statement No. 44 concerned accounting for intangible assets of motor carriers, and Statement No. 13, “Accounting for Leases” was amended to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the +required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The provisions related to Statement 13 are effective for transactions occurring after May 15, 2002, and the remaining +provisions of the statement are effective for fiscal years beginning after May 15, 2002. The Company adopted this new statement after issuance in April 2002; however, there were no lease transactions during the period between May 15, 2002 and June +29, 2002 that would be covered under the provisions of the statement. This new statement, in its entirety, is in effect for the Company’s fiscal year beginning June 30, 2002. Adoption of this statement did not have a material impact on the +Company’s consolidated financial statements. +Statement of Financial +Accounting Standards No. 146, “Accounting for Costs Associated With Exit or Disposal Activities”, was issued in June 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities +and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)” by requiring that a +liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. The provisions of this statement are effective for exit or disposal activities that are +initiated after December 31, 2002. The Company adopted SFAS No. 146 on June 30, 2002 for exit or disposal activities initiated after December 31, 2002. Adoption of this statement did not have a material impact on the Company’s consolidated +financial statements. +In December 2002, the FASB issued SFAS No. 148 +“Accounting for Stock-Based Compensation, Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of +accounting for stock-based employee compensation. It also amends the disclosure provisions of SFAS No. 123 to require prominent disclosure about the effects of reported net income of an entity’s accounting policy decisions with respect to +stock-based employee compensation. Finally, this Statement amends APB Opinion No. 28, Interim Financial Reporting, to require disclosure about those effects in interim financial information. The amendments to SFAS No. 123, which provides alternative +methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation is effective for financial statements for fiscal years ending after December 15, 2002. The amendment to +SFAS No. 123 relating to disclosures and the amendment to Opinion 28 is effective for financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. The Company has adopted the disclosure +provisions of SFAS No. 148 on its 2003 financial statements. As the Company does not intend to adopt the fair value provisions of FAS No. 123, the Company does not believe that implementing SFAS No. 148 will have a material impact on its +consolidated financial statements. +26 +Table of Contents +In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging +Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging +activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”. SFAS No. 149 is effective for all contracts created or modified after June 30, 2003. The Company does not believe that the adoption of +this standard will have a material effect on its consolidated financial statements. +In November 2002, the FASB issued Interpretation (FIN) No. 45, which requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantees. It also requires +disclosure in interim and annual financial statements of its obligations under certain guarantees it has issued. The initial recognition and measurement provisions of FIN No. 45 are to be applied prospectively to guarantees issued or modified after +December 31, 2002. The disclosure requirements are effective for financial statements for periods ending after December 15, 2002. Adoption of FIN No. 45 did not have a material effect on its consolidated financial statements. +In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest +Entities”. FIN No. 46 clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements, to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do +not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. A variable interest entity is required to be consolidated by the Company that has a majority of the +exposure to expected losses of the variable interest entity. The Interpretation is effective immediately for variable interest entities created after January 31, 2003. For variable interest entities in which an enterprise holds a variable interest +that it acquired before February 1, 2003, the Interpretation applies in the first fiscal year or interim period beginning after June 15, 2003. The Company does not believe the issuance of this Interpretation will have a material impact on its +consolidated financial statements. +In May 2003, the FASB issued SFAS No. 150, +“Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both +liabilities and equity. The Standard requires that certain freestanding financial instruments be classified as liabilities, including mandatorily redeemable financial instruments, obligations to repurchase the issuer’s equity shares by +transferring assets and certain obligations to issue a variable number of shares. SFAS No. 150 is effective for financial instruments entered into or modified subsequent to May 31, 2003, and otherwise is effective at the beginning of the first +interim period beginning after June 15, 2003. It is to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of the Statement and still existing at the +beginning of the interim period of adoption. The Company does not anticipate that the implementation of this Standard will have a material impact on its consolidated financial statements. +Reclassifications +Certain reclassifications of prior year balances have been made for consistent presentation with the current year. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2003, 2002, and +2001 ended on June 28, 2003, June 29, 2002, and June 30, 2001, respectively. Fiscal year 2004 will end on July 3, 2004. +2. INVENTORIES +Components of inventories were as follows: +June 28, 2003 +June 29, 2002 +(in thousands) +Finished goods +$ +9,439 +$ +8,323 +Work-in-process +3,117 +2,002 +Raw materials +15,108 +12,835 +Reserve for obsolescence +(3,513 +) +(4,765 +) +$ +24,151 +$ +18,395 +27 +Table of Contents +3. PROPERTY, PLANT AND EQUIPMENT +Life +June 28, 2003 +June 29, 2002 +(in years) +(in thousands) +Land +— +$ +1,730 +$ +1,730 +Buildings and improvements +3 to 30 +11,165 +11,021 +Equipment +1 to 10 +67,315 +66,363 +Furniture and fixtures +3 to 5 +6,259 +6,172 +$ +86,469 +$ +85,286 +In December of 2000, the Company sold +its headquarters building, located in Spokane, Washington, associated land (Parcel 1), and adjacent property (Parcel 2). In conjunction with the sale, the Company entered into a ten year lease agreement for a portion of the building, located on +Parcel 1, and guaranteed one year of rent on the vacant portion. The company allocated the proceeds from the sale between the building, Parcel 1, and Parcel 2, in the amount of $3.2 million, $801,000, and $1.1 million, respectively. The associated +net book value of the assets sold were $1.8 million, $322,000, and $434,000 respectively. The Company immediately recognized the gain on the sale of Parcel 2, in the amount of $648,000, and deferred the gain associated with Parcel 1 and the building +for one and ten years, respectively. On December 27, 2001, upon culmination of the Company’s guaranteed rent obligation, the Company recognized the proceeds allocated to the building, net of the guaranteed rent payments of $745,500, and +recognized a gain in the amount of $479,000 on Parcel 1, which was included within other income. The remaining gain, allocated to the building was deferred under other long-term obligations and will be amortized to other income over the remaining +lease term. +In February of 2002, the Company sold its Cheney, Washington, +facility, which had previously been recorded as real estate held for sale, for $1.7 million, resulting in a gain of $84,000, recorded within other income. +4. LONG-TERM DEBT +On August 22, 2001, the Company entered into a financing agreement with CIT Group/Business Credit, Inc. which provides a revolving credit facility up to $25 million. The new revolving loan is secured by the assets of +the Company. The interest rate provisions of the agreement specify four alternative levels of margin to be added to the prime rate ranging from 0.25% to 1.00% depending on compliance with certain financial covenants. For the first year of the +financing agreement with CIT, a margin of 0.75% was added to the prime rate. The prime rate is based on the JP Morgan Chase prime rate. The margin applicable at June 28, 2003 was 0.50%. The full rate of interest as of June 28, 2003 was 4.50%. On +November 19, 2002 a third amendment to the financing agreement was signed. The amendment contains financial covenants that relate to total equity, earnings before interest, taxes, depreciation and amortization, and a minimum fixed charge ratio. The +amendment also extended the term of the agreement by one year. The agreement became effective on August 24, 2001, and will now terminate on August 23, 2005. In addition to the financial covenants, the credit agreement restricts investments, +distribution of assets and the payment of dividends. As of June 28, 2003, the Company was in compliance with all loan covenants. At June 28, 2003, the outstanding revolving credit balance was $9,864,000 compared to $6,475,000 at June 29, 2002. The +Company’s revolving loan will become due and payable on August 23, 2005. At June 28, 2003, approximately $3.0 million was available under the credit facility. +5. INCOME TAXES +Income tax expense (benefit) consists of the following: +Year Ended +June 28, +2003 +June 29, +2002 +June 30, +2001 +(in thousands) +Current income taxes: +Federal +$ +(37 +) +$ +— +$ +— +Foreign +637 +900 +643 +State +— +— +— +600 +900 +643 +Deferred income taxes: +Federal +4,264 +(7,627 +) +(4,598 +) +Foreign +— +— +— +State +272 +(723 +) +(34 +) +4,536 +(8,350 +) +(4,632 +) +Change in valuation allowance +(4,536 +) +12,866 +4,632 +0 +4,516 +0 +Total income tax expense +$ +600 +$ +5,416 +$ +643 +28 +Table of Contents +The Company’s effective tax rate differs from the federal tax rate as follows: +Year Ended +June 28, 2003 +June 29, 2002 +June 30, 2001 +(in thousands) +Federal income tax expense (benefit) at statutory rates +$ +4,763 +$ +(6,782 +) +$ +(3,648 +) +Effect of foreign taxes +435 +807 +293 +State tax (net of federal effect) +272 +(723 +) +— +Permanent differences: +Life insurance premiums +56 +50 +43 +Other +(390 +) +(802 +) +(677 +) +Change in valuation allowance +(4,536 +) +12,866 +4,632 +Income tax provision +$ +600 +$ +5,416 +$ +643 +The domestic and foreign components of +income before income taxes were: +Year Ended +June 28, 2003 +June 29, 2002 +June 30, 2001 +(in thousands) +Domestic +$ +13,414 +$ +(20,219 +) +$ +(11,759 +) +Foreign +595 +273 +1,029 +Income (loss) before income taxes +$ +14,009 +$ +(19,946 +) +$ +(10,730 +) +Deferred income taxes result from +temporary differences in the timing of recognition of revenue and expenses. Deferred income tax assets and liabilities consist of the following at: +June 28, 2003 +June 29, 2002 +(in thousands) +Allowance for doubtful accounts +$ +32 +$ +122 +Inventory +1,462 +2,537 +Vacation accrual +346 +360 +Self insurance accrual +52 +58 +Warranty accrual +55 +100 +State deferred asset +71 +943 +Litigation judgment (current portion) +382 +99 +Other +80 +— +Current deferred income tax assets +2,480 +4,219 +Current portion of valuation allowance +(2,480 +) +(4,219 +) +Current deferred income tax assets, net of valuation allowance +— +— +Depreciation and amortization +$ +885 +$ +1,718 +State deferred taxes +600 +— +Litigation judgment (non-current portion) +882 +6,523 +Net operating loss carryforwards +18,396 +15,260 +Tax credit carryforwards +607 +680 +Other +270 +256 +Noncurrent deferred income tax assets +21,640 +24,437 +Valuation allowance, net of current portion +(21,640 +) +(24,437 +) +Noncurrent deferred income tax assets, net of valuation allowance +$ +— +$ +— +Total deferred income tax assets +$ +— +$ +— +29 +Table of Contents +Financial Accounting Standard No. 109 requires that management assess the sources of future taxable income, which may be +available to recognize the deductible differences that comprise deferred tax assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or all of the deferred tax assets will not be realized. +Management has determined that a valuation allowance equal to the net deferred tax assets is appropriate. +At June 28, 2003, the Company had regular and alternative minimum tax net operating loss carryforwards approximating $54 million each. The net operating loss carryforwards expire in varying amounts from fiscal years +ending in 2006 through 2022. The Company also has general business credits and alternative minimum tax credits approximating $424,000 and $183,000, respectively. The general business credits expire in varying amounts from fiscal years ending in +years 2004 through 2009 and the alternative minimum tax credits do not expire. +6. EARNINGS PER SHARE +Basic EPS is computed by dividing net +income (loss) (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by dividing net income (loss) by the weighted-average number of common shares and common share +equivalents outstanding during the period. Total weighted average shares outstanding for the fiscal years ended June 28, 2003, June 29, 2002 and June 30, 2001 were 9,672,580, 9,672,580, and 9,667,785 respectively. The number of stock options +outstanding for the fiscal 2003, 2002 and 2001 periods were 2,086,086, 2,081,304 and 1,966,200 respectively. As of June 28, 2003, none of the outstanding options were dilutive and therefore have been excluded from earnings per share. As of June 29, +2002 and June 30, 2001 respectively, 5,000 and 843,500 options were antidilutive. +7. STOCK OPTION AND BENEFIT PLANS +The Company has executive +stock option plans for certain key employees. Options under these plans vest over one to five years and become exercisable as they vest. Options under the plans become exercisable in full immediately prior to the occurrence of a “Change in +Control” as defined in the plan documents. The Company has reserved 2,795,000 shares for issuance under these plans. As of June 28, 2003, 1,878,586 options were outstanding of which 1,704,418 shares were exercisable. There are 105,800 shares +available for future grant under these option plans. These options expire in ten years from the date of grant. Compensation expense for options will be recorded if the exercise price of the option is less than the closing market price of the stock +on the date of grant. There was no compensation expense incurred in conjunction with options issued in fiscal years 2003, 2002, or 2001, respectively, as all options were granted at fair market value. See Note 1 for the pro forma effect if the +Company had accounted for the stock options using fair value methods. +The +Company also has a stock option plan for “Nonemployee Directors.” Options under this plan vest over a three-year period and are exercisable as they vest. The Company has reserved 300,000 shares for issuance under this plan. As of June 28, +2003, 207,500 options were outstanding of which 144,999 shares were exercisable. There are 62,150 shares available for future grant under this plan. These options expire ten years from the date of grant. +See Note 1 for the pro forma effect if the Company had accounted for the stock options using +fair value methods. +Following is a summary of plan activity: +Price Range +Number +Of Options +Weighted Average +Exercise Price +Outstanding, July 1, 2000 +$ +2.75 to $16.25 +2,046,140 +$ +4.98 +Granted during 2001 +$ +1.54 to $ 5.03 +63,500 +$ +4.26 +Expired or canceled +$ +2.75 to $16.25 +(112,190 +) +$ +4.98 +Options exercised +$ +2.75 to $ 3.31 +(31,250 +) +$ +2.86 +Outstanding, June 30, 2001 +$ +1.54 to $16.25 +1,966,200 +$ +4.99 +Granted during 2002 +$ +2.00 to $ 2.11 +130,000 +$ +2.07 +Expired or canceled +$ +2.75 to $ 7.25 +(14,896 +) +$ +4.12 +Outstanding, June 29, 2002 +$ +1.54 to $16.25 +2,081,304 +$ +4.81 +Granted during 2003 +$ +1.15 to $ 1.20 +160,000 +$ +1.16 +Expired +$ +1.15 to $16.25 +(155,218 +) +$ +6.04 +Outstanding, June 28, 2003 +$ +2.75 to $16.25 +2,086,086 +$ +4.44 +30 +Table of Contents +Additional information regarding options outstanding as of June 28, 2003, is as follows: +Options +Outstanding +Options +Exercisable +Range of +Exercise Prices +Number +Outstanding +Weighted Avg. +Remaining +Contractual +Life (yrs.) +Weighted +Avg. Exercise +Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$ 1.15 - $ 1.73 +155,000 +7.0 +$ +1.17 +3,333 +$ +1.54 +$ 1.74 - $ 2.60 +130,000 +6.2 +$ +2.07 +48,332 +$ +2.06 +$ 2.61 - $ 3.92 +789,000 +7.4 +$ +2.79 +789,000 +$ +2.79 +$ 3.93 - $ 5.89 +685,200 +5.9 +$ +5.07 +681,866 +$ +5.07 +$ 5.90 - $ 8.85 +218,941 +4.6 +$ +7.48 +218,941 +$ +7.48 +$ 8.86 - $13.30 +40,945 +0.7 +$ +10.03 +40,945 +$ +10.03 +$13.31 - $16.25 +67,000 +3.6 +$ +16.25 +67,000 +$ +16.25 +$ 1.15 - $16.25 +2,086,086 +6.3 +$ +4.44 +1,849,417 +$ +4.81 +The Company’s Variable Investment +Plan is available to U.S. employees who have attained age 21. The plan has an Employer’s Discretionary Contribution Trust, invested in the Company’s stock, and an Employee Contribution Trust consisting of several investment alternatives. +The Company contributes an amount equal to 100% of the employee’s contribution on the first 2% of the employee’s compensation and an additional 50% of the employee’s contribution on the following 2% of the employee’s +compensation. On April 1, 2001, the Company began matching 25% on the next 2% of contributions. Company contributions to the Trust were $366,190, $362,458 and $334,863 in fiscal years 2003, 2002 and 2001, respectively. The Company also has an +Employee Stock Ownership Plan that currently has no assets. No contributions were made to the plan in fiscal years 2003, 2002 or 2001. +8. COMMITMENTS AND CONTINGENCIES +Leases: The Company has operating leases for certain equipment and production facilities, which expire at various dates during the next eight years. Future minimum +payments under non-cancelable operating leases with initial or remaining terms of one year or more at June 28, 2003, are summarized as follows: +Fiscal Years Ending +(in thousands) +2004 +$ +3,225 +2005 +2,034 +2006 +1,229 +2007 +605 +2008 +444 +Future +1,103 +Total minimum lease payments +$ +8,640 +Rental expenses under operating leases +were $4,601,000, $4,548,000, and $4,358,000 in 2003, 2002, and 2001, respectively. +Warranty Costs: The Company provides warranties on certain product sales and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires us to make estimates of +product return rates and expected costs to repair or to replace the products under warranty. We currently establish warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior +twelve months’ sales activities. If actual return rates and/or repair and replacement costs differ significantly from our estimates, adjustments to recognize additional cost of sales may be required in future periods. +31 +Table of Contents +Components of the reserve for warranty costs during 2003, 2002, and 2001 were as follows: +Balance at July 1, 2000 +$ +453,759 +Additions related to current period sales +220,000 +Warranty costs incurred in the current period +(347,214 +) +Balance at June 30, 2001 +326,545 +Additions related to current period sales +215,101 +Warranty costs incurred in the current period +(247,376 +) +Balance at June 29, 2002 +294,270 +Additions related to current period sales +150,000 +Warranty costs incurred in the current period +(283,126 +) +Balance at June 28, 2003 +$ +161,144 +Litigation Settlement : On +December 20, 2001, a jury in Seattle federal court rendered a verdict in the case of F&G Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic Corporation, United States District +Court for the Western District of Washington, Case No. C99-995C (the “litigation”) finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury awarded damages to the Plaintiffs +in the amount of $16.5 million. The judgment against the Company was subsequently increased to approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a settlement of the litigation with the +Plaintiffs (hereafter called “F&G”). Under the terms of the settlement, the Company has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G of $2.5 million, as well as make +quarterly payments to F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is greater, until the total payment of $7.0 million has been made, provided the total payment is completed by December 15, 2005. During fiscal year +2003, the Company made payments to F&G totaling approximately $3.3 million. +If the total of $7.0 million is not paid by 12/15/2005, the total settlement amount increases on 12/15/2005 to $7.6 million. If payment of $7.6 million is not completed by 12/15/2006 the total settlement amount increases to $8.2 million. If +payment of $8.2 million is not completed by 12/15/2007 the total settlement amount increases to $8.8 million. If payment of $8.8 million is not completed by 12/15/2008 the total settlement amount increases to $9.7 million. If payment of $9.7 million +is not completed by 12/15/2009 the total settlement amount increases to $10.6 million. If payment of $10.6 million is not made by 12/15/2010 the total settlement amount increases to $11.5 million. Any unpaid balance remaining at 12/15/2011 will +accrue interest thereafter at prime plus 1½% per annum until paid. If the Company fails to make any minimum quarterly payment when due, Plaintiffs have the right to accelerate all remaining payments in the amount of $11.5 million less any +amounts previously paid. +Reported earnings for the fiscal year ended June 28, +2003, include a one-time benefit of $12.2 million ($1.26 per share) for a revision of the litigation accrual. +9. ENTERPRISE-WIDE DISCLOSURES +Management organizes its business around EMS and keyboards based on geographic area. These businesses have been aggregated as each segment has similar economic characteristics, and the nature of the segments, its production processes, +customers and distribution methods are similar. +Of the revenues for the years +ended June 28, 2003, June 29, 2002 and June 30, 2001, EMS sales were $116.0 million, $157.0 million, and $126.3 million, respectively. Keyboard sales for the years ended June 28, 2003, June 29, 2002 and June 30, 2001 were $14.6 million, $18.3 +million, and $38.6 million, respectively. The remainder of revenues for all years presented were from sales of miscellaneous other products and services. +32 +Table of Contents +Information concerning geographic areas for the years ended June 28, 2003, June 29, 2002 and June 30, 2001 is summarized +in the following table. Revenues provided below are based on the shipping destination. +Domestic +International +Total +(in thousands) +2003 +Net sales +$ +114,674 +$ +16,220 +$ +130,894 +Long-lived assets +$ +10,974 +$ +1,008 +$ +11,982 +2002 +Net sales +$ +143,324 +$ +32,267 +$ +175,591 +Long-lived assets +$ +11,429 +$ +803 +$ +12,232 +2001 +Net sales +$ +76,950 +$ +88,915 +$ +165,865 +Long-lived assets +$ +15,629 +$ +1,040 +$ +16,669 +For the year ended June 28, 2003, +71.7% of the Company’s domestic exports were to customers in the Far East, 14.6% were sold to customers in Mexico, 10.0% were sold to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +For the year ended June 29, 2002, 45.4% of the Company’s domestic exports +were sold to customers in Mexico, 44.3% were sold to customers in the Far East, 6.6% were sold to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +For the year ended June 30, 2001, 42.8% of the Company’s domestic exports were sold to +customers in the Far East, 29.7% were sold to customers in Mexico, 25.7% were sold to customers in Europe, and the remaining 2% were spread among customers in South America and Canada. +Significant Customers +At present, the Company’s customer base is highly concentrated and could become even more concentrated. The Company’s largest EMS customer accounted for 31% of +net sales in fiscal year 2003. This same customer accounted for 39% of sales in 2002 and 0% in 2001. Three of the Company’s EMS customers accounted for 9%, 8%, and 8% of net sales during fiscal year 2003. These same customers accounted for 10%, +13%, and 10% of net sales in fiscal year 2002 and 0%, 27%, and 39% in fiscal year 2001. There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the +Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major +customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +10. QUARTERLY FINANCIAL DATA +(Unaudited) +Year Ended June 28, 2003 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +34,034 +$ +30,552 +$ +30,645 +$ +35,663 +Gross profit +$ +3,506 +$ +3,484 +$ +3,778 +$ +4,190 +Income before income taxes +$ +12,718 +$ +190 +$ +320 +$ +781 +Net income +$ +12,479 +$ +74 +$ +306 +$ +550 +Earnings per common share basic and diluted +$ +1.29 +$ +.01 +$ +.03 +$ +.06 +Weighted average shares +Outstanding - basic +9,673 +9,673 +9,673 +9,673 +Diluted shares outstanding +9,673 +9,673 +9,675 +9,714 +33 +Table of Contents +Year Ended June 29, 2002 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +34,627 +$ +50,516 +$ +46,515 +$ +43,933 +Gross profit +$ +2,132 +$ +4,877 +$ +4,300 +$ +3,676 +Income (loss) before income taxes +$ +(1,205 +) +$ +(16,140 +) +$ +481 +$ +(3,082 +) +Net income (loss) +$ +(982 +) +$ +(21,595 +) +$ +399 +$ +(3,184 +) +Earnings (loss) per common share basic and diluted +$ +(.10 +) +$ +(2.23 +) +$ +.04 +$ +(.33 +) +Weighted average shares +Outstanding - basic +9,673 +9,673 +9,673 +9,673 +Diluted shares outstanding +N/A +N/A +9,673 +N/A +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +On December 3, 2002 Deloitte & Touche, LLP (“D&T”) was dismissed as the Company’s independent public accountants and +BDO Seidman, LLP (“BDO”) was appointed as the Company’s new independent accountants to replace D&T for the fiscal year ending June 28, 2003. The decision to dismiss D&T and to appoint BDO was made and approved by the Audit +Committee. D&T’s reports on the Company’s financial statements for the past two fiscal years did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting +principles. During the prior two fiscal years and through December 3, 2002, there were no disagreements with D&T on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which +disagreements, if not resolved to the satisfaction of D&T would have caused that firm to make reference to the subject matter of the disagreements in connection with its reports; and there were no reportable events as defined in certain SEC +regulations. Prior to the engagement of BDO the Company had not consulted with BDO during the prior two fiscal years and through December 3, 2002 in any matter regarding the application of accounting principles on a specified transaction, either +completed or proposed, or the type of audit opinion that might be rendered on the Company’s financial statements, or any other matters or reportable events as defined in certain SEC regulations. See Form 8-K dated December 3, 2002. +Item 9A: +CONTROLS AND PROCEDURES +a) +An evaluation was performed under the supervision and with the participation of the Company’s chief executive officer and chief financial officer, of the effectiveness of the +design and operation of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s +disclosure controls and procedures were effective. +b) +There have been no significant changes in the Company’s internal controls or in other factors which could significantly affect internal controls subsequent to the date the +Company carried out the evaluation. +34 +Table of Contents +PART III +Item 10: +DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +DALE F. PILZ - Director +Mr. Pilz, age 77, has been a director of the Company since April 1992. On January 27, 2000, Mr. Pilz was elected Chairman of the Board. Mr. Pilz was Chief Executive +Officer of Flowind Corporation from 1986 to 1990. He served as President of Omninet Corporation from 1985 to 1986. Prior to that, Mr. Pilz was Chief Executive Officer and President of GTE Sprint Communications from 1983 to 1985 and also served as +Chief Executive Officer and President of GTE Spacenet Corporation from 1983 to 1985. +WENDELL J. SATRE - Director +Mr. Satre, age 85, has +been a director of the Company since 1988 and served as Chairman of the Board of Directors from July 1991 through August 1995. Mr. Satre also served as a director from 1983 through 1986 and served as Acting President of the Company from August 1991 +through February 1992. Mr. Satre is the retired Chairman of the Board and Chief Executive Officer of the Washington Water Power Company, a public utility headquartered in Spokane, Washington. Mr. Satre also serves on the Board of Directors of Output +Technology Corporation and The Coeur d’Alenes Company. +YACOV A. +SHAMASH - Director +Dr. Shamash, age 53, has been a director of the +Company since 1989. He has been the Dean of Engineering and Applied Sciences at the State University of New York campus at Stony Brook since 1992. Professor Shamash developed and directed the NSF Industry/University Cooperative Research Center for +the Design of Analog/Digital Integrated Circuits from 1989 to 1992 and also served as Chairman of the Electrical and Computer Engineering Department at Washington State University from 1985 until 1992 . +WILLIAM E. TERRY - Director +Mr. Terry, age 70, has been a director of the Company since August 1992. Mr. Terry retired +from Hewlett-Packard in December 1993 where he served in a number of executive positions during the past 36 years. He is a member of the Advisory Committee of the Santa Clara University Engineering School and, in 1983, was elected to the +university’s Board of Regents. Mr. Terry also serves on the Board of Directors of Altera Corporation. +PATRICK SWEENEY - Director +Mr. +Sweeney, age 68, has been a director of the Company since July 2000. Mr. Sweeney was President and CEO of Hadco Corporation from 1991 through 1995 and formerly served as Hadco’s Vice President/Chief Financial Officer and Vice President of +Operations. Prior to that, Mr. Sweeney was the Vice President of International Manufacturing at Wang - USA from 1981 through 1986 and also served as Managing Director of Ireland for Wang and Plant Manager of Digital Equipment Corporation’s +Galway and Clonmel divisions. Mr. Sweeney also serves on the Board of Directors of Aimware, Zaig Tech., Info. Mosaic, Photo Machining Inc., Piercom and Raidtec. He is also a member of the Advisory Board of Manufacturers’ Services Ltd. +JACK W. OEHLKE - Director, President and Chief Executive +Officer +Mr. Oehlke, age 57, has been President and Chief Executive +officer of the Company since June 1997. From October 1995, he served as Chief Operating Officer. Previously, he served as Senior Vice President of Operations from January 1995 to October 1995 and Vice President of Manufacturing Operations of the +Company from December 1993 to January 1995. Mr. Oehlke served as Director of Operations, Director of Quality and in various management positions within manufacturing, engineering and quality functions of the Microswitch Division of Honeywell, Inc. +from 1968 to 1993. Mr. Oehlke has a Bachelor of Science Degree in Industrial Technology from the University of Wisconsin at Menomonie. +35 +Table of Contents +RONALD F. KLAWITTER - Executive Vice President of Administration and Chief Financial Officer +Mr. Klawitter, age 51, has been Executive Vice President of Administration, +CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary and Treasurer of the Company since October 1995. He was Acting Secretary from November 1994 to October 1995 and Vice President of Finance and Treasurer from +1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President, Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. He has a BA degree from Wittenberg University and is a Certified Public Accountant. +CRAIG D. GATES - Executive Vice President of Marketing, Engineering, and Sales +Mr. Gates, age 44, has been Executive Vice President of Marketing, +Engineering and Sales since July 1997. Previously he was Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. Mr. Gates has a +Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. From 1982 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., +in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. +EFREN R. PEREZ - Vice President of S.W. Operations +Mr. Perez, age 63, has served as Vice President of S.W. Operations since July 1997. Previously he was the Managing Director of S.W. Operations from July 1996 to July 1997 +and Director of S.W. Operations from July 1995 to June 1996. Following the Company’s acquisition of the Honeywell, Inc. Keyboard Division, Mr. Perez served as Plant Manager in Juarez from July 1993 to July 1995. He served as Plant Manager in +Juarez for the Keyboard Division of Honeywell, Inc. from February 1989 to July 1993. Mr. Perez is a graduate of the University of Mexico with a B.S. in Physics. +MICHAEL D. CHARD - Vice President of Materials +Mr. Chard, age 45, has been Vice President of Materials of the Company since July 28, 2000. From February 1999 to July 28, 2000, he held +various management positions with the Company in planning, quality assurance, and materials. From January 1997 to January 1999, he was Vice President of Product Delivery at Wang Global and its predecessor Olivetti North America. From 1983 to 1996, +he held various management positions in finance, marketing, and operations at ISC Systems, the predecessor to Olivetti North America. He holds a BA Degree in Business and Accounting from Washington State University and is a Certified Public +Accountant. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2003 Proxy +Statement to Shareholders. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2003 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 28, 2003. +36 +Table of Contents +EQUITY COMPENSATION PLAN INFORMATION +Plan category +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 reflected in +column (a)) +(c) +Equity compensation plans approved by security holders +1,706,586 +4.91 +122,450 +Equity compensation plans not approved by security holders (1) +379,500 +2.33 +45,500 +Total +2,086,086 +4.44 +167,950 +(1) +Consists of the Key Tronic Corporation 2000 Employee Stock Option Plan +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2003 Proxy Statement is incorporated +herein by this reference. +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in +the Company’s 2003 Proxy Statement is incorporated herein by this reference. +37 +Table of Contents +PART IV +Item 15: +EXHIBITS, FINANCIAL STATEMENT SCHEDULE, REPORTS ON FORM 8-K, AND SIGNATURES +(A) FINANCIAL STATEMENTS AND SCHEDULE +Page in +Form 10-K +FINANCIAL STATEMENTS +Reports of Independent Certified Public Accountants +17-18 +Consolidated Balance Sheets, as of June 28, 2003, and June 29, 2002 +19 +Consolidated Statements of Operations for the years ended June 28, 2003, June 29, 2002, and June 30, 2001 +20 +Consolidated Statements of Shareholders’ Equity for the years ended June 28, 2003, June 29, 2002, and June 30, 2001 +21 +Consolidated Statements of Cash Flows for the years ended June 28, 2003, June 29, 2002, and June 30, 2001 +22 +Notes to Consolidated Financial Statements +23-34 +SCHEDULE +Independent Auditors’ Report on Financial Statement Schedule +40 +II. Consolidated Valuation and Qualifying Accounts +41 +Other schedules are omitted because of +the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +REPORTS ON FORM 8-K +(a) +April 29, 2003 – Conference Call, text of management’s remarks. +(b) +April 29, 2003 – Press release. +(C) EXHIBITS +The Company will, upon request and upon payment of a reasonable fee not to exceed the rate at which such copies are available from the Securities and Exchange Commission, furnish copies of any of the following +exhibits to its security holders. +Exhibit No. +(3) +(a) +Articles of Incorporation +(ii) +(b) +By-Laws, as amended +(ii) +(c) +Certification of Chief Executive Officer (Exchange Act Rules 13(a)-14 and 15(d)-14) +31.1 +(d) +Certification of Chief Financial Officer (Exchange Act Rules 13(a)-14 and 15(d)-14) +31.2 +(e) +Certification of Chief Executive Officer (18 U.S.C. 1350) +32.1 +(f) +Certification of Chief Financial Officer (18 U.S.C. 1350) +32.2 +(4) +Certain long-term debt is described in Note 4 to the Consolidated Financial Statements of the +Company. The Company agrees to furnish to the Commission, upon +request, copies of any +instruments defining rights of holders of long-term debt described in Note 4. +N/A +(10) +Material Contracts +(a) +Retention Bonus Plan +(i) +(b) +Employee Contracts +(i) +(c) +Third Amendment to Financing Agreement +(i) +(d) +Fourth Amendment to Financing Agreement +10.1 +38 +Table of Contents +(i) +Incorporated by reference to Form 10-Q for the quarter ended December 28, 2002 +(ii) +Incorporated by reference to report on Form 10-K for the year ended June 30, 1986 +(21) Subsidiaries of Registrant +1. +KT Services, Inc. +2. +KTI Limited +100% owned subsidiary +100% owned by Key Tronic Europe, LTD +Incorporated in the State of Washington +Incorporated in Ireland +3. +Key Tronic Europe, LTD +4. +Key Tronic Juarez, SA de CV +100% owned subsidiary +100% owned subsidiary +Incorporated in the Cayman Islands +Incorporated in Mexico +5. +Key Tronic China LTD +6. +Key Tronic Computer Peripherals (Shanghai) Co. LTD +100% owned subsidiary +100% owned subsidiary +Incorporated in the State of Washington +Incorporated in Republic of China +7. +Key Tronic Reynosa, S.A. de CV +100% owned subsidiary +Incorporated in Mexico +39 +Table of Contents +(23.1) CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS +The Board of Directors and Shareholders +Key +Tronic Corporation +Spokane, Washington +We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-70917 and 333-61202) of Key Tronic Corporation and subsidiaries of +our report dated August 14, 2003, relating to the consolidated financial statements and financial statement schedule as of and for the year ended June 28, 2003, which appears in this Form 10-K. +/s/ BDO Seidman, LLP +September 15, 2003 +Spokane, Washington +(23.2) +INDEPENDENT AUDITORS’ CONSENT AND REPORT ON FINANCIAL STATEMENT SCHEDULE +We consent to the incorporation by reference in Registration Statement No. 333-70917 and 333-61202 on Form S-8 of our report dated August 16, 2002 appearing in this +Annual Report on Form 10-K of Key Tronic Corporation and subsidiaries (the Company) for the year ended June 28, 2003. +We have audited the consolidated financial statements of the Company as of June 29, 2002 and for each of the two years in the period ended June 29, 2002 and have issues +our report thereon dated August 16, 2002 such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company, listed in Item 14(A). This financial statement schedule is the +responsibility of the Company’s management. +Our responsibility is to +express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects the +information set forth therein. +DELOITTE & TOUCHE LLP +Seattle, Washington +September 17, 2003 +40 +Table of Contents +PART IV +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 28, 2003, JUNE 29, 2002, AND +JUNE 30, 2001 +2003 +2002 +2001 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +4,765 +$ +2,712 +$ +2,349 +Provisions +203 +2,225 +435 +Dispositions +(1,455 +) +(172 +) +(72 +) +Balance at end of year +$ +3,513 +$ +4,765 +$ +2,712 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +444 +$ +633 +$ +855 +(Recovery) provisions +(56 +) +175 +714 +Write-offs and reinstatements +(283 +) +(364 +) +(936 +) +Balance at end of year +$ +105 +$ +444 +$ +633 +41 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +Dated: September 19, 2003 +KEY TRONIC CORPORATION +By: +/s/ Jack W. Oehlke +Jack W. Oehlke, Director, President, +and Chief Executive Officer +42 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by +the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/Jack W. Oehlke +September 19, 2003 +Jack W. Oehlke +Date +(Director, President and +Chief Executive Officer) +/s/Ronald F. Klawitter +September 19, 2003 +Ronald F. Klawitter +Date +(Principal Financial Officer) +/s/Dale F. Pilz +September 19, 2003 +Dale F. Pilz +Date +(Director) +/s/Wendell J. Satre +September 19, 2003 +Wendell J. Satre +Date +(Director) +/s/Yacov A. Shamash +September 19, 2003 +Yacov A. Shamash +Date +(Director) +/s/Patrick Sweeney +September 19, 2003 +Patrick Sweeney +Date +(Director) +/s/William E. Terry +September 19, 2003 +William E. Terry +Date +(Director) +43 \ No newline at end of file diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/filing_metadata.csv b/raw/filings/0000719733/2003/0001193125-03-051450/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..82b8c6d47f919a61c3838dd6f77650e99277a352 --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2003-09-19,2003-06-28,2003-09-18T21:43:34.000Z,0001193125-03-051450,d10k.htm,"FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 28, 2003",802544,0,0,https://www.sec.gov/Archives/edgar/data/719733/000119312503051450/d10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000119312503051450/,2003,2003,1 diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/item1.txt b/raw/filings/0000719733/2003/0001193125-03-051450/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..02abfb9c3ae0489b8de3d9e5e728db925695e185 --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/item1.txt @@ -0,0 +1,356 @@ +Item 1. +BUSINESS +Key Tronic Corporation (dba KeyTronicEMS), a Washington corporation organized in 1969, and its subsidiaries (hereinafter collectively called the “Company” or “Key Tronic” unless the context +otherwise requires) are principally engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs). The Company also manufactures keyboards for personal computers, terminals, and workstations primarily in standard +layouts that can be sold directly from inventory on hand. +BACKGROUND +Historically, Key Tronic was a manufacturer of only electronic keyboards, +but about five years ago, after assessing its strengths and capabilities, the Company’s focus was shifted to electronic manufacturing services (EMS). Presently, Key Tronic is known as an independent provider of a mix of EMS services for OEMs. +The Company’s manufacturing capabilities include tool making, precision molding, prototype design, liquid plastic injection molding, printed circuit board assembly (both through-hole and surface-mount), and full box build. +Operations are currently conducted in facilities in the United States, China, Ireland and +Mexico. This global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower transportation costs and reduced product fulfillment time. +The EMS industry is comprised of companies that provide a range of manufacturing services for +OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to external manufacturing, and it is expected to continue in this growth pattern for several years. +CUSTOMERS AND MARKETING +OEM MARKETS +The Company provides manufacturing services for outsourced OEM products. Key Tronic is capable of providing a mix of EMS services including product design, tool making, +precision molding, prototype design, liquid plastic injection molding, printed circuit board assembly, full box builds, and printing screened silver flexible circuit membranes. The percentage of revenues from EMS services for the fiscal years ended +June 28, 2003, June 29, 2002, and June 30, 2001 were 88.6%, 89.4%, and 76.2%, respectively. Sales of such products are generally not seasonal in nature. +Clorox accounted for 31% of consolidated revenue in fiscal year 2003 compared to 39% in fiscal year 2002. Hewlett Packard accounted for approximately 8%, 10%, and 39% of +the Company’s consolidated revenues in fiscal years 2003, 2002, and 2001, respectively. Lexmark accounted for 8%, 13%, and 27% of consolidated revenues in fiscal years 2003, 2002, and 2001, respectively. No other customers accounted for 10% or +more of consolidated revenues in the three fiscal years presented. In the fiscal years ended June 28, 2003, June 29, 2002, and June 30, 2001, the five largest customers, including Clorox, Hewlett Packard, and Lexmark, accounted for 63%, 76%, and 81% +of total sales, respectively. +3 +Table of Contents +Although keyboard manufacturing is still included in the Company’s product offerings, annual sales continue to +decline. During the fiscal years ended June 28, 2003, June 29, 2002, and June 30, 2001, the Company realized revenues of approximately $14.6 million, $18.3 million, and $38.6 million, respectively, from the sale of keyboards representing +approximately 11.1%, 10.4%, and 23.3% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the demand for standard products, the Company maintains a purchase-from-stock +program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original system-supplied keyboards. Keyboard sales can increase somewhat during the last +half of each calendar year in conjunction with the holiday season, but generally sales of these products are not seasonal in nature. +The Company markets its products and services primarily through its direct sales organization aided by strategically located field sales people and distributors. Although +the Company established relationships with several independent sales organizations to assist in marketing the Company’s EMS product lines in the U.S., commissions earned and paid during fiscal year 2003 were insignificant. +MANUFACTURING +Since inception, the Company has made substantial investments in developing and expanding its now extensive capital equipment base to +achieve selective vertical integration in its manufacturing processes. The Company designs and develops tooling for injection molding machines and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the +Company has invested in equipment to produce printed screened silver flexible circuit membranes. +The Company’s automated manufacturing processes enable it to work closely with its customers during design and prototype stages of production for new custom products and to jointly increase productivity and +reduce response time to the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality +and enhance turnaround time during product development. +Key Tronic uses a +variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, surface-mount technology, flexible robotic assembly, +computerized vision system quality inspection, automated switch and keytop installation, and automated functional testing. +The Company purchases materials and components for its products from many different suppliers both domestic and international. Key Tronic develops close working +relationships with its suppliers, many of whom have been supplying products to the Company for several years. +FOREIGN MARKETS +Information concerning +geographic areas for the years ended June 28, 2003, June 29, 2002, and June 30, 2001 is summarized in the following table. +(in thousands) +Domestic +Exports +U.S. +Operations +Mexico +Operations +Europe +Operations +Far East +Operations +Eliminations +Consolidated +2003 +Net sales: +Unaffiliated customers +$ +11,940 +$ +114,674 +$ +— +$ +4,280 +$ +— +$ +— +$ +130,894 +Affiliates +$ +2,248 +$ +— +$ +27,864 +$ +18 +$ +17,232 +$ +(47,362 +) +$ +— +Total +$ +14,188 +$ +114,674 +$ +27,864 +$ +4,298 +$ +17,232 +$ +(47,362 +) +$ +130,894 +Income (loss) before income taxes +$ +— +$ +11,110 +$ +2,304 +$ +(21 +) +$ +716 +$ +(100 +) +$ +14,009 +Total assets +$ +— +$ +46,439 +$ +8,533 +$ +3,134 +$ +6,806 +$ +(5,787 +) +$ +59,125 +4 +Table of Contents +(in thousands) +Domestic +Exports +U.S. +Operations +Mexico +Operations +Europe +Operations +Far East +Operations +Eliminations +Consolidated +2002 +Net sales: +Unaffiliated customers +$ +26,888 +$ +143,324 +$ +— +$ +5,291 +$ +88 +$ +— +$ +175,591 +Affiliates +$ +— +$ +3,187 +$ +40,438 +$ +(60 +) +$ +19,037 +$ +(62,602 +) +$ +— +Total +$ +26,888 +$ +146,511 +$ +40,438 +$ +5,231 +$ +19,125 +$ +(62,602 +) +$ +175,591 +Income (loss) before income taxes +$ +— +$ +(22,242 +) +$ +2,023 +$ +(885 +) +$ +948 +$ +210 +$ +(19,946 +) +Total assets +$ +— +$ +38,940 +$ +14,658 +$ +3,161 +$ +9,511 +$ +(8,831 +) +$ +57,439 +2001 +Net sales: +Unaffiliated customers +$ +77,842 +$ +76,950 +$ +— +$ +9,617 +$ +1,456 +$ +— +$ +165,865 +Affiliates +$ +— +$ +6,355 +$ +41,829 +$ +12 +$ +22,312 +$ +(70,508 +) +$ +— +Total +$ +77,842 +$ +83,305 +$ +41,829 +$ +9,629 +$ +23,768 +$ +(70,508 +) +$ +165,865 +Income (loss) before income taxes +$ +— +$ +(14,714 +) +$ +2,955 +$ +(978 +) +$ +1,865 +$ +142 +$ +(10,730 +) +Total assets +$ +— +$ +68,394 +$ +20,703 +$ +5,879 +$ +8,056 +$ +(28,661 +) +$ +74,371 +Foreign sales from worldwide +operations, including domestic exports, were $16.2 million in fiscal year 2003 compared to $32.3 million and $88.9 million in fiscal years 2002 and 2001, respectively. Foreign sales were 12.4% of net sales in fiscal 2003 compared to 18.4% and 53.6% +in fiscal years 2002 and 2001, respectively. The decrease in foreign sales for fiscal year 2003 is primarily the result of declining sales to the foreign subsidiaries of one EMS customer. Sales from Key Tronic Europe, Ltd. represented approximately +3.3% of consolidated sales to external customers in fiscal year 2003 compared to 3.0% and 5.8% in fiscal years 2002 and 2001, respectively. Although the Company hopes to expand its EMS business to include the European market, sales within Europe at +the present time are primarily for electronic keyboards. Key Tronic Computer Peripheral Co., Ltd., the Company’s subsidiary in Shanghai, China, did not have any local sales in fiscal year 2003. In fiscal years 2002 and 2001, local sales from +this subsidiary were $88,000 and $1.5 million, respectively. The decrease in sales to local Chinese customers is also the result of lower purchases from the same EMS customer as previously discussed. +For additional financial information about foreign operations, see Note 9 to the Consolidated +Financial Statements. +BACKLOG +At August 2, 2003, the Company had an order backlog of approximately $34.9 million. This +compares with a backlog of approximately $24.6 million at August 3, 2002. Order backlog is not necessarily indicative of future sales. Order backlog consists of purchase orders received for products expected to be shipped approximately within the +next fiscal year, although shipment dates are subject to change due to design modifications or other customer requirements. +RESEARCH, DEVELOPMENT, AND ENGINEERING +The Company’s research, development, and engineering expenses (RD&E) were $2.9 million, $2.6 million, and $2.7 million in fiscal years 2003, 2002, and 2001, +respectively. Research, development and engineering expenses as a percentage of sales were 2.2%, 1.5%, and 1.6% in fiscal years 2003, 2002, and 2001, respectively. The slight increase in RD&E expenses in fiscal year 2003 was due primarily to +reinstated employee wages and merit increases that were under a 10% pay reduction in fiscal year 2002, and a reduction in rebillable engineering services. +COMPETITION +The Company believes that its principal competitors in the EMS market are divided into three tiers, the first tier includes such companies as Solectron, Celestica and Flextronics. The second tier has several companies +with smaller market capitalization such as Plexus, Pemstar and Suntron. The Company believes they are positioned in the third tier, which includes SMTC, Nortech, and IEC Electronics. The principal methods of competition are price, quality, and the +range of services offered. +5 +Table of Contents +TRADEMARKS AND PATENTS +The Company owns several keyboard patents; however, since the Company’s focus is now electronic manufacturing services, management believes that these patents +will not have a significant impact on future revenues. The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets in its business. In fiscal year 2001, Key Tronic began operating under the +trade name “KeyTronicEMS” to better represent its primary business concentration. +EMPLOYEES +As of June 28, 2003, the +Company had approximately 2,687 employees compared to 1,995 on June 29, 2002. The increase in employees is due primarily to additional production workers hired in the Company’s Juarez facility to ramp-up for more labor intensive customer +programs. The Company’s employees in Ireland and Reynosa are represented by local unions. The Company has never experienced any material interruption of production due to labor disputes. +The Company’s employee benefit program includes bonus programs involving periodic +payments to all employees based on quarterly or fiscal year before-tax income. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution on a portion of the employee’s contribution, and also provides +group health, life, and disability insurance plans. The Company also maintains stock option plans for certain employees and outside directors. \ No newline at end of file diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/item13.txt b/raw/filings/0000719733/2003/0001193125-03-051450/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..02066650f8494bc6880064bd77a94c39ea71d864 --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/item13.txt @@ -0,0 +1,6 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in +the Company’s 2003 Proxy Statement is incorporated herein by this reference. +37 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/item9a.txt b/raw/filings/0000719733/2003/0001193125-03-051450/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..2acbf1f714c7bba66922defbb86782314d91692e --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/item9a.txt @@ -0,0 +1,12 @@ +Item 9A: +CONTROLS AND PROCEDURES +a) +An evaluation was performed under the supervision and with the participation of the Company’s chief executive officer and chief financial officer, of the effectiveness of the +design and operation of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s +disclosure controls and procedures were effective. +b) +There have been no significant changes in the Company’s internal controls or in other factors which could significantly affect internal controls subsequent to the date the +Company carried out the evaluation. +34 +Table of Contents +PART III \ No newline at end of file diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/rp_note.txt b/raw/filings/0000719733/2003/0001193125-03-051450/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2003/0001193125-03-051450/rpt_disclosure.txt b/raw/filings/0000719733/2003/0001193125-03-051450/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ac54b426f10b010516d3fb04d988af7cdaf4444f --- /dev/null +++ b/raw/filings/0000719733/2003/0001193125-03-051450/rpt_disclosure.txt @@ -0,0 +1,14 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +See Compensation Committee Interlocks and Insider Participation in Compensation Decisions, page 10. +In October 2002, the Board of Directors approved retention bonus plans for Messrs. Oehlke, Gates and Klawitter. Under the retention bonus plan, Mr. Oehlke became eligible +to receive retention bonus payments in August of 2003, 2004 and 2005, if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts under Mr. Oehlke’s retention bonus plan are +$211,250 for 2003, $243,750 for 2004 and $276,250 for 2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Oehlke pursuant to any Company incentive plans during the fiscal year immediately +preceding the retention bonus payment date. +Under the retention bonus plan, +Mr. Gates became eligible to receive on the payment date retention bonus payments in August of 2003, 2004 and 2005 if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts +under Mr. Gates retention bonus plan are $119,000 for 2003, $142,800 for 2004 and $166,600 for 2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Gates pursuant to any Company incentive +plans during the fiscal year immediately preceding the retention bonus payment date. +13 +Under the retention bonus plan, Mr. Klawitter became eligible to receive retention bonus payments in August of 2003, 2004 +and 2005 if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts under Mr. Klawitter’s retention bonus plan are $119,000 for 2003, $142,800 for 2004 and $166,600 for +2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Klawitter pursuant to any Company incentive plans during the fiscal year immediately preceding the retention bonus payment date. \ No newline at end of file diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/filing.txt b/raw/filings/0000719733/2004/0001193125-04-157946/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..eda71eab3a604e209e8ecc3612f74aa5365f2f80 --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/filing.txt @@ -0,0 +1,2928 @@ +10-K +1 +d10k.htm +FOR THE FISCAL YEAR ENDED JULY 3, 2004 +For the fiscal year ended July 3, 2004 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended July 3, 2004 +OR +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 0-11559 +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +Washington +91-0849125 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road +Spokane Valley, Washington +99216 +(Address of principal executive offices) +(Zip Code) +Registrant’s +telephone number, including area code: (509) 928-8000 +Securities Registered Pursuant to Section 12(b) of the Act: None +Securities Registered Pursuant to Section 12(g) of the Act: Common stock, +no par value +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the +preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements during the past 90 days. Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not +contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant +is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨ No x . +The aggregate market value of the voting stock held by non-affiliates of the Registrant was $21,281,076 as of December 27, 2003. +The number of shares of Common Stock of the Registrant outstanding as of September 3, 2004 was 9,675,913 shares. +The Exhibit Index is located at pages 40 - 41. +Documents Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 24, 2004 +Part III +Table of Contents +KEY TRONIC CORPORATION +2004 FORM 10-K +TABLE OF CONTENTS +Page +Part I +Item 1. +Business +3 - 5 +Item 2. +Properties +6 +Item 3. +Legal Proceedings +7 +Item 4. +Submission of Matters to a Vote of Security Holders +7 +Part II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +8 +Item 6. +Selected Financial Data +8 - 9 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +9 - 17 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +17 +Item 8. +Financial Statements and Supplementary Data +18 - 35 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +36 +Item 9A. +Controls and Procedures +36 +Item 9B. +Other Information +36 +Part III +Item 10. +Directors and Executive Officers of the Registrant +37 - 38 +Item 11. +Executive Compensation +38 +Item 12. +Security Ownership of Certain Beneficial Owners and Management +38 - 39 +Item 13. +Certain Relationships and Related Transactions +39 +Item 14. +Principal Accounting Fees and Services +39 +Part IV +Item 15. +Exhibits and Financial Statement Schedules +40 - 42 +Signatures +43 -44 +2 +Table of Contents +FORWARD-LOOKING STATEMENTS +This Annual Report contains forward-looking statements in addition to historical information. Forward-looking statements are subject to +certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in +“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, +which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to revise or publicly release the results of any revision to forward-looking statements. Readers should carefully review the risk factors +described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q. +PART I +Item 1. BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, +and its subsidiaries (hereinafter collectively called the “Company”, “Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related +products manufacturing for original equipment manufacturers (OEMs). The Company also manufactures keyboards and other input devices for personal computers, terminals, and workstations primarily in standard layouts that can be sold directly from +inventory on hand. +Presently, Key Tronic is known as an independent provider +of product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing its strengths and capabilities, the Company shifted its focus to electronic +manufacturing services (EMS). +Operations are currently conducted in facilities +in the United States, China, Mexico, and Ireland. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs and reduced +product fulfillment time. +The EMS industry is comprised of companies that +provide a range of manufacturing services for OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to outsourcing manufacturing, and this trend is expected to continue in the future. +Marketing +The Company provides manufacturing services for outsourced OEM products. Key Tronic provides a mix of EMS services including: product +design, surface mount technologies (SMT) for printed circuit assembly, tool making, precision molding, liquid plastic injection molding, prototype design, full box builds, and printing screened silver flexible circuit membranes. +The percentage of revenues from EMS services for the fiscal years ended July 3, 2004, June +28, 2003, and June 29, 2002 were 91.1%, 88.6%, and 89.4%, respectively. Sales of such products have historically not been seasonal in nature, but may be seasonal in the future, due to changes in the types of products manufactured. +The following customers accounted for 10% or more of consolidated revenues in the three +fiscal years presented below: +Fiscal Year +2004 +2003 +2002 +The Clorox Company +16 +% +31 +% +39 +% +Lexmark International, Inc. +14 +% +8 +% +18 +% +Zebra Technologies Corporation +12 +% +8 +% +0 +% +Transaction Printer Group, Inc. +10 +% +9 +% +10 +% +Hewlett-Packard Company +1 +% +8 +% +13 +% +For the fiscal years ended July 3, +2004, June 28, 2003, and June 29, 2002, the five largest customers in each year accounted for 58%, 64%, and 85% of total sales, respectively. +3 +Table of Contents +Although keyboard manufacturing is still included in the Company’s product offerings, annual keyboard sales continue +to decline. During the fiscal years ended July 3, 2004, June 28, 2003, and June 29, 2002, the Company realized revenues of approximately $12.9 million, $14.6 million, and $18.3 million, respectively, from the sale of keyboards representing +approximately 8.7%, 11.1%, and 10.4% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the demand for standard products, the Company maintains a purchase-from-stock +program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original system-supplied keyboards. +The Company markets its products and services primarily through its direct sales department +aided by strategically located field sales people and distributors. Although the Company established relationships with several independent sales organizations to assist in marketing the Company’s EMS product lines in the U.S., commissions +earned and paid are insignificant. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding an +extensive capital equipment base to achieve selective vertical integration in its manufacturing processes. The Company has invested significant capital into surface mount technologies (SMT) for high volume manufacturing of complex printed circuit +board assemblies. The Company designs and develops tooling for injection molding machines and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the Company has invested in equipment to produce printed +flexible circuit membranes. +Key Tronic uses a variety of manual and highly +automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, SMT, flexible robotic assembly, computerized vision system quality inspection, automated +switch and keytop installation, and automated functional testing. +The +Company’s automated manufacturing processes enable it to work closely with its customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. Key Tronic uses +computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround time during product development. +The Company purchases materials and components for its products from many +different suppliers both domestic and international. Key Tronic develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas as of and for the years ended +July 3, 2004, June 28, 2003, and June 29, 2002 is summarized in the following table. Net sales provided below are based on the shipping destination. +Domestic (U.S.) +Foreign +Total +(in thousands) +2004 +Net sales +$ +134,413 +$ +14,488 +$ +148,901 +Long-lived assets +$ +10,153 +$ +978 +$ +11,131 +2003 +Net sales +$ +114,674 +$ +16,220 +$ +130,894 +Long-lived assets +$ +10,974 +$ +1,008 +$ +11,982 +2002 +Net sales +$ +143,324 +$ +32,267 +$ +175,591 +Long-lived assets +$ +11,429 +$ +803 +$ +12,232 +For the year ended July 3, 2004, 44.5% +of the Company’s foreign net sales were to customers in Mexico, 29.7% were to customers in Europe, 20.1% were to customers in Canada, and the remaining 5.7% were spread among customers in Asia and South America. +For the year ended June 28, 2003, 71.7% of the Company’s foreign net sales were to +customers in the Far East, 14.6% were to customers in Mexico, 10.0% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +4 +Table of Contents +For the year ended June 29, 2002, 45.4% of the Company’s foreign net sales were sold to customers in Mexico, 44.3% +were to customers in the Far East, 6.6% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +Backlog +At August 1, 2004, the Company had an order backlog of approximately $68.1 million. This compares with a backlog of approximately $34.9 million at August 2, 2003. Order backlog is not necessarily indicative of future +sales but can be indicative of trends in expected future sales revenue. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next fiscal year, although shipment dates are subject to change +due to design modifications, customer forecast changes, or other customer requirements. +Research, Development, and Engineering +Research and +development and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. The Company’s RD&E +expenses were $2.6 million, $2.9 million, and $2.6 million in fiscal years 2004, 2003, and 2002, respectively. In fiscal years 2004, 2003, and 2002, the Company focused most of its RD&E efforts on current customer EMS programs. The higher cost +in fiscal year 2003 compared to fiscal years 2004 and 2002 is due primarily to a 10% pay reduction during most of fiscal years 2004 and 2002. Part of the increase in 2003 was due to a decrease in the amounts charged to the Company’s customers. +Competition +The market for the products and services the Company provides is highly competitive. There +are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and +price. +Trademarks and Patents +The Company owns several keyboard patents; however, since the Company’s current focus +is electronic manufacturing services, management believes that these patents will not have a significant impact on future revenues. The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets +of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS Co.” to better identify its primary business concentration. +Employees +As of July 3, 2004, the Company had approximately 2,847 employees compared to 2,687 on June 28, 2003 and 1,995 on June 29, 2002. The increase in employees is due +primarily to additional production workers hired in the Company’s Juarez facility to ramp-up for more labor intensive customer programs. The Company can have significant fluctuations in product demand. The Company seeks to maintain flexibility +in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition to full-time employees. The Company’s employees in Reynosa, Mexico, are represented by local unions. The Company has no +history of any material interruption of production due to labor disputes. +The +Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The Company’s employee benefits include bonus programs involving periodic payments to all employees based on meeting +quarterly or fiscal year before-tax income targets. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% on a portion of the employee’s contribution, and also provides group health, +life, and disability insurance plans. The Company also maintains stock option plans for certain employees and outside directors. +5 +Table of Contents +Item 2. PROPERTIES +The Company has manufacturing +and sales operations located in the United States, Mexico, China, and Ireland. The table below lists the locations and square footage of the Company’s facilities as of July 3, 2004: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane, Washington (1) +49,000 +Leased +Research and administration +Spokane, Washington +96,000 +Leased +Manufacturing +Las Cruces, New Mexico +45,000 +Owned +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +270,000 +Juarez, Mexico (2) +174,000 +Owned +Manufacturing +Juarez, Mexico +49,000 +Leased +Manufacturing and warehouse +Juarez, Mexico (3) +38,000 +Leased +Manufacturing and warehouse +Reynosa, Mexico +140,000 +Leased +Manufacturing +Reynosa, Mexico (4) +48,000 +Leased +Warehouse +Total Mexico +449,000 +Shanghai, China (5) +63,000 +Leased +Manufacturing +Total China +63,000 +Dundalk, Ireland +4,000 +Leased +Sales +Total Ireland +4,000 +Grand Total +786,000 +(1) +On December 27, 2000, the Company sold two contiguous parcels of land and its corporate headquarters building in Spokane to Royal Hills Associates L.L.C. (RHA) for +approximately $6 million in cash. In connection with the sale, the Company entered into a 10-year lease agreement with RHA for one floor of the two-story building, which the Company continues to occupy as its headquarters (see Note 3 to Consolidated +Financial Statements). The Company’s monthly rent payment is $30,875 plus allocated expenses. +(2) +The Company added 9,000 square feet to its main manufacturing facility in Juarez, Mexico during fiscal year 2004 to accommodate a new 3,000 ton press molding machine +and improve product flow of outbound shipping. +(3) +In May 2004, the Company leased an additional 38,000 square foot manufacturing facility in Juarez, Mexico for new product assembly space and warehouse storage. +(4) +In July 2003, the Company leased an additional 48,000 square foot warehouse in Reynosa, Mexico for storage capacity. +(5) +The Company began an assembly operation in Shanghai, China in fiscal year 1999. During fiscal year 2003, the leased space was increased from 36,000 sq. ft. to 63,000 +sq. ft. to accommodate a new surface mount technology (SMT) line for automated circuit board production. +The geographic diversity of these locations allows the Company to offer services near its customers and its major electronics markets, while reducing labor costs. The +Company considers the productive capacity of its current facilities sufficient to carry on the Company’s current business. +6 +Table of Contents +Item 3. LEGAL PROCEEDINGS +On December 20, 2001, a +jury in Seattle federal court rendered a verdict in the case of F&G Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic Corporation, United States District Court for the Western +District of Washington, Case No. C99-995C (the “litigation”) finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury awarded damages to the Plaintiffs in the amount of $16.5 +million. The judgment against the Company was subsequently increased to approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a settlement of the litigation with the Plaintiffs (hereafter +called “F&G”). Under the terms of the settlement, the Company has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G of $2.5 million, as well as make quarterly payments to +F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is greater, until the total payment of $7.0 million has been made, provided the total payment is completed by December 15, 2005. The remaining amount to be paid of the $7.0 +million settlement was approximately $2.5 million at July 3, 2004. +If the +total of $7.0 million is not paid by 12/15/2005, the total settlement amount increases on 12/15/2005 to $7.6 million. If payment of $7.6 million is not completed by 12/15/2006 the total settlement amount increases to $8.2 million. If payment of $8.2 +million is not completed by 12/15/2007 the total settlement amount increases to $8.8 million. If payment of $8.8 million is not completed by 12/15/2008 the total settlement amount increases to $9.7 million. If payment of $9.7 million is not +completed by 12/15/2009 the total settlement amount increases to $10.6 million. If payment of $10.6 million is not made by 12/15/2010 the total settlement amount increases to $11.5 million. Any unpaid balance remaining at 12/15/2011 will accrue +interest thereafter at prime plus 1 1 / 2 % per annum until paid. If the Company fails to make any minimum quarterly +payment when due, Plaintiffs have the right to accelerate all remaining payments in the amount of $11.5 million less any amounts previously paid. +Reported earnings for the year ended June 28, 2003, include a one-time benefit of $12.2 million ($1.26 per share) for reversal of a previously recorded litigation +accrual. +On March 31, 2004 a former employee of the Company filed a complaint +against the Company in the Superior Court of the State of Washington, Spokane County. Anthony DeStefano, Jr. v Key Tronic Corporation , Case No. 04201480-2. The complaint asserted claims for breach of contract, wrongful withholding of wages +and wrongful discharge and sought an unspecified amount of damages. The complaint was dismissed with prejudice on September 8, 2004 with each party bearing its own costs. +The Company is party to certain other lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, +individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Also see Note 8 to the Consolidated Financial Statements. +Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None +7 +Table of Contents +PART II +Item 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Key Tronic Corporation’s common stock is traded on the NASDAQ National Market System under the symbol “KTCC”. Quarterly high and low closing sales prices for Key Tronic common stock for fiscal years +2004 and 2003 were as follows: +2004 +2003 +High +Low +High +Low +First Quarter +$ +2.65 +$ +2.30 +$ +1.20 +$ +0.28 +Second Quarter +2.49 +1.96 +1.45 +0.30 +Third Quarter +3.00 +2.20 +1.40 +1.05 +Fourth Quarter +4.06 +2.66 +2.85 +1.05 +High and low stock prices are based on +the daily closing price reported by the NASDAQ National Market System. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders And Dividends +As of July 3, 2004, the Company had 1,380 shareholders of record. The Company’s current financing agreement contains a covenant that +prohibits the declaration or payment of dividends (see Note 4 to Consolidated Financial Statements). The Company has not paid a cash dividend and does not anticipate payment of dividends in the foreseeable future. +Item 6: SELECTED FINANCIAL DATA +The following +selected consolidated financial data of the Company should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, +and other information included in this report. +Financial Highlights +(Dollars in thousands, except per share amounts) +Fiscal Years +2004 +2003 +2002 +2001 +2000 +Consolidated Statements of Operations Data : +Net sales +$ +148,901 +$ +130,894 +$ +175,591 +$ +165,865 +$ +164,353 +Gross profit +13,237 +14,958 +14,985 +7,556 +14,458 +Gross margin percentage +8.9 +% +11.4 +% +8.5 +% +4.6 +% +8.8 +% +Operating income (loss) +1,789 +2,612 +1,224 +(9,484 +) +(3,460 +) +Operating margin percentage +1.2 +% +2.0 +% +0.7 +% +(5.7 +)% +(2.1 +)% +Litigation/settlement recovery (expense) +— +12,186 +(20,214 +) +— +— +Net income (loss) +110 +13,409 +(25,362 +) +(11,373 +) +(5,333 +) +Earnings per share – diluted +0.01 +1.39 +2.62 +(1.18 +) +(0.55 +) +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations +(17 +) +(544 +) +919 +7,481 +3,256 +Capital expenditures +1,633 +2,128 +1,142 +720 +1,439 +Consolidated Balance Sheet Data : +Net working capital (1) +23,468 +21,783 +22,261 +22,886 +37,128 +Total assets +67,938 +59,125 +57,439 +74,371 +95,815 +Long-term liabilities +13,452 +13,553 +26,823 +9,389 +17,555 +Shareholders’ equity +23,234 +23,120 +9,711 +35,318 +46,602 +Book value per share (2) +2.40 +2.39 +1.00 +3.65 +4.83 +Supplemental Data : +Number of shares outstanding at year-end (thousands) +9,676 +9,673 +9,673 +9,673 +9,641 +Number of employees at year-end +2,847 +2,687 +1,995 +2,151 +1,926 +Approximate square footage of leased/ owned facilities +786,000 +691,000 +664,000 +615,000 +665,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed +by long term funds and is an indicator of short term financial management. +8 +Table of Contents +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. Book value per share +measures shareholders’ value as defined by generally accepted accounting principles. +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Results of Operations +Overview +Key Tronic Corporation is an independent provider of electronic manufacturing services (EMS) for original equipment manufacturers (OEMs). The Company’s core +strengths include innovative design and engineering expertise in SMT, electronics, mechanical engineering, precision molding and tooling, combined with high-quality, low-cost production and assembly on a global basis. Our global production +capability provides customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. The following information should be read in conjunction with the consolidated +financial statements included herein and the “Risk and Uncertainties” section beginning on page 16. +The EMS industry has historically experienced growth as more OEMs shift to outsourced manufacturing. Key Tronic sales in fiscal year 2004 increased by 14% over 2003 results. With the current turnaround of end-market +demand and recent new product programs awarded, the Company expects to increase revenues once again in fiscal year 2005 – however, actual results will depend on actual levels of customer orders. We believe that we are well positioned in the EMS +industry to expand our customer base and continue business growth within our current capacity. +The total number of Key Tronic EMS customers continued to increase during fiscal 2004. Some of these customers have programs that represent small annual sales while others have multi-million-dollar potential. The +concentration of the Company’s largest customers has also declined as the top five customers sales decreased to 58% of total sales in 2004 from 64% in 2003 and 85% in 2002. The Company’s current customer relationships involve a variety of +products, including consumer electronics and plastics, household products, gaming devices, specialty printers, educational toys, exercise equipment, and computer accessories. +The EMS industry is intensely competitive, and Key Tronic, at this time, estimates it has less than 1% of the potential market. The Company +believes that it can acquire new business in the future, particularly those programs that require innovative design and engineering, short lead times, or small initial volumes. The Company is planning for growth in coming quarters by utilizing +current capacity, improving manufacturing processes, and investing in additional manufacturing equipment. +The Company maintains a strong balance sheet with a current ratio of 1.75 and a long-term debt to equity ratio of 0.58. The Company had approximately $9.1 million available from a revolving line of credit at July 3, +2004. The Company maintains a good working relationship with CIT Group/Business Credit, Inc., its asset-based lender, and it believes that internally generated funds and its revolving line of credit should provide adequate capital for planned +growth. +Net Sales +Net sales in fiscal 2004 were $148.9 compared to $130.9 million and $175.6 million in fiscal +years 2003 and 2002, respectively. The increase during 2004 compared to 2003 is related to the Company’s successful expansion of the number of manufacturing +9 +Table of Contents +programs with existing customers and acquiring new significant customers during the year, offset in part, by a large +decrease in demand from a single customer. Sales revenue resulting from new customers attained in 2004 was approximately $8.2 million, while the net increase of sales to existing customers was approximately $9.8 million. Sales of keyboards accounted +for only 8.7% of total sales in fiscal 2004 compared to 11.1% in fiscal 2003. +The decrease in sales revenue during 2003 compared to 2002 is due to decreased shipments to some of the Company’s primary customers as a result of a slowdown in end-market demand and the effects of a legal judgment on our ability to +acquire new customers. This legal judgment was settled in the second quarter of fiscal 2003, and further information is set forth in Note 8 of the Consolidated Financial Statements contained herein. Sales revenue resulting from new customers +acquired in 2003 was approximately $5.4 million, while the net decrease of sales to existing customers was approximately $50.1 million. Keyboard sales were 11.1% of sales in fiscal 2003 compared to 10.4% in fiscal 2002. +Gross Profit +In fiscal year 2004, gross profit on sales was 8.9% of revenues compared to 11.4% in fiscal +year 2003 and 8.5% in fiscal year 2002. The decrease in 2004 was due primarily to the product mix and costs associated with the start-up of new manufacturing programs, offset in part by an insurance settlement in 2004 of $475,000. The increase in +the gross profit percentage in fiscal year 2003 compared to fiscal year 2002 was due primarily to the product mix, improvements in operating efficiencies, and lower material costs. +Gross profit margins reflect a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies +associated with new programs, product life cycles, sales volumes, capacity utilization of the Company’s resources, management of inventories, component pricing and shortages, end market demand of our customers’ products, fluctuations and +timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in our operating results. There can be no assurance that gross margins will not decrease in future periods. +Cost of Sales +Total costs of material as a percentage of sales were approximately 58.1%, 57.0%, and 64.8% +in fiscal years 2004, 2003, and 2002, respectively. The change from year-to-year is directly related to sales product mix. Products sold in 2004 and 2003 were more labor intensive, thereby decreasing costs of material as a percentage of sales. +Direct production costs (direct labor and manufacturing overhead) have +increased to 18.3% of total sales in fiscal 2004 from 16.0% in 2003 and 15.6% in 2002. Approximately half of the increase in 2004 is the result of start-up costs associated with new manufacturing programs. These start-up costs included increasing +the Company’s manufacturing and storage space in Juarez, Mexico. The remaining increase in 2004 is due primarily to additional employees required for more labor-intensive products. +The Company provides for obsolete and non-saleable inventories based on specific identification of inventory against current demand and +recent usage. The amounts charged to expense were $162,000, $203,000, and $2,225,000 in fiscal years 2004, 2003, and 2002, respectively. +The Company provides for warranty costs based on historical experience and anticipated product returns. The amounts charged to expense were fairly consistent at +approximately $193,000, $150,000, and $215,000 in fiscal years 2004, 2003, and 2002, respectively. The Company does not warrant design defects for EMS customers. +Cost of sales also includes freight costs of $2.5 million in fiscal year 2004 compared to $2.0 million in fiscal year 2002, and $2.4 million +in fiscal year 2001. Freight costs have increased to 1.8% of total sales in 2004 from 1.5% in 2003 and 1.4% in 2002. The Company’s freight costs have increased as the Company continues to expand global procurement and as a result of increased +shipping rates and fuel surcharges. +Research, Development and Engineering +Research and +development and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. The Company’s RD&E +expenses were $2.6 million, $2.9 million, and $2.6 million in fiscal years 2004, 2003, and 2002, respectively. In fiscal years 2004, 2003, and 2002, the Company focused most of its RD&E efforts on current customer EMS programs. The higher cost +in fiscal year 2003 compared to fiscal years 2004 and 2002 is due primarily to a 10% pay reduction during most of fiscal years 2004 and 2002. Part of the increase in 2003 was due to a decrease in the amounts charged to the Company’s customers. +10 +Table of Contents +Selling +Sales and marketing expenses consist principally of advertising and marketing programs, salaries and benefits for sales and marketing +personnel, sales commissions, and travel expenses. Selling expenses were $1.9 million, $2.3 million, and $2.8 million in fiscal years 2004, 2003, and 2002, respectively. The decrease in 2004 was related to a reduction in promotional programs, +commissions, and bonuses paid. The decreases in fiscal year 2003 compared to fiscal year 2002 were due primarily to a reduction in promotional programs and marketing expenses related to keyboard sales. Sales of keyboards through distribution require +greater promotional and marketing programs than sales of EMS products. +General and Administrative +General and +administrative expenses consist of employee related costs, travel expenses and allocated information technology and facilities costs for finance, legal, human resources and executive functions, outside legal and accounting fees, provision for +doubtful accounts and business insurance costs. General and administrative expenses were $7.0 million, $7.2 million and $8.4 million in fiscal years 2004, 2003, and 2002, respectively. The decrease in fiscal year 2004 compared to fiscal year 2003 +was due primarily to a 10% reduction in salaries that was in effect for most of the fiscal year offset in part by increasing business insurance premiums. The decrease in fiscal year 2003 compared to 2002 was primarily due to a year over year decline +in legal expenses as a result of the settlement of the F&G litigation. Other contributing factors were a decreased provision for doubtful accounts, lower telephone expenses, decreased staffing in Ireland, and the adoption of SFAS 142, which +ceased the amortization of goodwill. +Interest Expense +The Company had net interest expenses of +$1.1 million, $1.0 million, and $1.3 million in fiscal years 2004, 2003, and 2002, respectively. Net interest expense has remained fairly consistent, as the Company has increased its borrowings while interest rates have decreased. The Company does +not currently use derivatives in hedging interest rate risk. During 2004, the Company began to utilize short-term fixed LIBOR rates on portions of its revolver for short-term interest savings in anticipation of rate increases. +Other Income, Net +The Company had net other income of $23,000, $237,000, and $358,000 in fiscal years 2004, +2003, and 2002, respectively. Other income in fiscal year 2003 is primarily proceeds from the sale of an equity security. The other income for fiscal year 2002 is primarily the result of recognizing gains on the sale of two of the Company’s +buildings and related equipment. +Income +Tax Provision +The Company had income tax expense of $611,000 in fiscal +year 2004 compared to $600,000 in fiscal year 2003 and $5,416,000 in fiscal year 2002. The tax provisions for fiscal years 2004 and 2003 are primarily the result of foreign taxes on the earnings of foreign subsidiaries. Income tax expense in fiscal +year 2002 was due primarily to establishing a 100% valuation allowance against the Company’s net deferred tax assets after a litigation judgment was awarded to F&G Scrolling Mouse. These assets totaled $4.5 million. Prior to the award of +this judgment, Key Tronic had almost $45.9 million in tax loss carry-forwards. Financial Accounting Standard No. 109 requires that management assess the sources of future taxable income, which may be available to recognize the deductible differences +that comprise deferred tax assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or all of the deferred tax assets will not be realized. Because the litigation judgment was considered evidence +of the Company’s possible inability to utilize the balance of the deferred tax assets, the valuation allowance was increased to the full value. The Company’s tax loss carry-forwards begin expiring in 2006. The remaining $900,000 of the +Company’s income tax provision in 2002 was due to foreign income taxes on the earnings of foreign subsidiaries. +International Subsidiaries +The Company offers customers a complete global manufacturing solution. The Company’s facilities provide its customers the opportunity to have their products +manufactured in the facility that best serves specific product manufacturing and distribution needs. Foreign subsidiaries are located in the following locations: +• +Key Tronic Juarez SA de CV, owns an SMT, assembly, and molding facility in Juarez, Mexico and currently leases two other facilities for assembly and storage. This subsidiary is +primarily used to support the Company’s U.S. operations. +• +Key Tronic Reynosa SA de CV, leases manufacturing and warehouse facilities in Reynosa, Mexico. This subsidiary is used exclusively to manufacture products for one EMS customer. +11 +Table of Contents +• +Key Tronic Computer Peripheral Co., Ltd., leases a facility with SMT and assembly capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide +EMS services for export; however, it is also currently utilized to manufacture electronic keyboards. +• +Key Tronic Europe, Ltd., the Company’s operation in Dundalk, Ireland, is primarily used to solicit sales and support customers within Europe. +Foreign sales from worldwide operations, including domestic exports, were $14.5 million in +fiscal year 2004 compared to $16.2 million and $32.3 million in fiscal years 2003 and 2002, respectively. Foreign sales were 9.7% of net sales in fiscal 2004 compared to 12.4% and 18.4% in fiscal years 2003 and 2002, respectively. Sales from Key +Tronic Europe, Ltd. represented approximately 2.0% of consolidated sales in fiscal year 2003 compared to 3.3% and 3.0% in fiscal years 2003 and 2002, respectively. The decrease in foreign sales for fiscal year 2004 when compared to fiscal year 2003 +is a result of declining keyboard sales from the Company’s subsidiary in Ireland. The decrease in foreign sales for fiscal year 2003 is primarily the result of declining sales to the foreign subsidiaries of one EMS customer and the continuing +decline of keyboard sales. Although the Company hopes to expand its EMS business to include the European market, sales within Europe currently are primarily of electronic keyboards. Key Tronic Computer Peripheral Co., Ltd., the Company’s +subsidiary in Shanghai, China, has had only minimal sales to customers in China over the past three fiscal years. +Capital Resources and Liquidity +Cash flows used in operating activities were $(17,000) in fiscal year 2004 compared to $(544,000) used in fiscal year 2003 and $919,000 of cash provided by operating +activities in fiscal year 2002. +The cash used in operations during fiscal year +2004 was due primarily to an increase of $7.4 million in accounts receivables and $3.9 million in inventory but these were offset by an increase in operating liabilities of $9.0 million. The increase in accounts receivable is due to an increase of +sales during the last two months of the fiscal year. The increase in inventory is due to a build up of raw materials for existing and new customers to support demand in the first quarter of 2005. Also contributing to the use of cash was $1.3 million +paid to F&G under the settlement agreement. +Capital expenditures were $1.6 +million, $2.1 million, and $1.1 million in fiscal years 2004, 2003, and 2002, respectively. The Company also uses a variety of operating leases to fund the purchase of operating equipment. +The Company’s primary financing activity in fiscal years 2004, 2003, and 2002 was +borrowing and repayment under the Company’s debt agreements. +The Company +has entered into a financing agreement with CIT Group/Business Credit, Inc. (CIT) which provides a revolving credit facility up to $20 million. The revolving loan is secured by the assets of the Company. The interest rate provisions allow for a +variable rate based on either the prime rate or LIBOR rate. The agreement specifies four alternative levels of margin to be added to these base rates depending on compliance with certain financial covenants. The range of interest being paid to CIT +on outstanding balances was 4.34 – 4.75% as of July 3, 2004. The agreement and subsequent amendments contain financial covenants that relate to total equity, earnings before interest, taxes, depreciation and amortization, and a minimum fixed +charge ratio. The revolving loan matures August 23, 2006. As of July 3, 2004, the Company was in compliance with all loan covenants. At July 3, 2004, the outstanding revolving loan balance was $10.9 million compared to $9.9 million at fiscal year +end June 28, 2003. The increase in the loan balance was due primarily to required payments to F&G in compliance with the settlement of the legal judgment and capital expenditures. Based on eligible collateral, approximately $9.1 million was +available from the revolving line of credit as of July 3, 2004. +In addition to +the Company’s revolving credit facility payment obligations and normal operating expenses, the Company has a $2.5 million litigation settlement payment obligation, various lease commitments, and other long term obligations of $1.1 million. +The Company believes that funds available under the revolving credit facility, +projected cash from operations, and leasing capabilities will be sufficient to meet our working and fixed capital requirements through fiscal year 2005 and the foreseeable future. +12 +Table of Contents +Contractual Obligations and Commitments +In the normal course of business, the Company enters into contracts, which obligate the Company to make payments in the future. +The table below sets forth the Company’s significant future obligations by fiscal +year: +Payments Due by Fiscal Year (in thousands) +Total +2005 +2006 +2007 +2008 +2009 +Thereafter +Litigation Settlement (1) +$ +2,461 +$ +925 +$ +1,536 +CIT Revolving Loan (2) +10,851 +10,851 +Capital and Operating Leases (3) +7,536 +3,173 +1,896 +868 +454 +445 +700 +Purchase Orders (4) +(1) +For an in-depth discussion of the litigation settlement, please see the Consolidated +Financial Statements at Note 8, “Commitments and Contingencies”. In accordance with the terms of the litigation settlement, the Company must pay a minimum of $200,000 or fifty percent of its operating earnings each quarter whichever is +greater. If the entire remainder of the settlement is not paid by December 15, 2005 additional amounts must be paid. Because payments exceeding $200,000 depend entirely on the Company’s operating earnings, which are not readily determinable, +the above table indicates the minimum payments for fiscal year 2005, and the remaining amount owing after those payments is shown in fiscal year 2006. At this time, the Company expects to pay the entire settlement amount by December 15, 2005. +(2) +The terms of the CIT revolving loan are discussed in the consolidated financial statements at +Note 4, “Long-Term Obligations”. The Company’s current financing agreement with CIT terminates on August 23, 2006, at which time the unpaid balance of the revolving loan will become immediately payable. However, the Company will more +likely than not extend or replace its revolving loan agreement prior to that date. The amount payable on the Company’s revolving loan changes daily depending upon the amount of cash borrowed to support its operations and the amount of customer +payments received. Under the terms of the Company’s agreement with CIT, all customers’ payments are applied against the outstanding revolving loan balance as soon as the amounts clear through the banking system. +Under the terms of the revolving credit agreement, the Company must meet a number of financial covenants. As of July 3, 2004 the Company was in +compliance with all of its loan covenants. Breaching one or more of these covenants could have a material impact on the Company’s operations or financial condition. +(3) +The Company maintains vertically integrated manufacturing operations in Mexico and Shanghai, +China. Such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, SMT lines, and automated insertion and test equipment for the various products the Company is capable of +producing. +In addition, the Company leases most of its administrative and manufacturing facilities. A complete discussion of +properties can be found in Part 1, Item 2 at “Properties”. Leases have proven to be an acceptable method for the Company to acquire new or replacement equipment and to maintain many facilities with a minimum impact on its operating cash +flows. +(4) +As of July 3, 2004, the Company had open purchase order commitments for materials and other +supplies of approximately $32 million. Of the $32 million in open purchase orders, there are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with the Company’s manufacturing levels. In +addition, the Company has contracts with its customers that minimize its exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified +ranges that are determined in negotiations with the Company’s suppliers. These agreements depend in part on the type of product purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented in tabular format, the Company also owes its +suppliers approximately $24.4 million for accounts payable and shipments in transit at the end of the fiscal year. The Company generally pays its suppliers in a range from 30 to 120 days depending on terms offered. Quarterly payments to suppliers +normally average between $20 and $25 million. These payments are financed by the Company’s revolving line of credit. +The Company believes that funds available under the revolving credit facility and internally generated funds can satisfy cash requirements for a period in excess of 12 +months. +13 +Table of Contents +Critical Accounting Policies +Revenue Recognition : The Company recognizes revenue primarily when products are shipped. Staff Accounting Bulletin 101 states that +revenue generally is realized or realizable and earned when all of the following criteria are met: +• +Persuasive evidence of an arrangement exists +• +Delivery has occurred or services have been rendered +• +The seller’s price to the buyer is fixed or determinable +• +Collectibility is reasonably assured +The Company believes that it meets the above criteria for the following reasons: +• +Customer purchase orders confirming the price and shipping terms are required prior to shipment. +• +The terms of the Company’s sales are generally FOB shipping point, meaning that the customer takes ownership of the goods and assumes the risk of loss when the goods leave the +Company’s premises. +• +The seller’s price to the buyer is fixed or determinable – as noted, we require a customer purchase order, which confirms the price and shipping terms. +• +Collectibility is reasonably assured – the credit terms for customers are pre-established so that collection of the account can be reasonably assured. +Inactive, Obsolete and Surplus Inventory Reserve : The Company reserves for +inventories that it deems inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that the Company produces. Demand is determined by expected sales or customer forecasts. If expected sales do not materialize, +then the Company would have inventory in excess of its reserves and would have to charge the excess against future earnings. In the case where the Company has purchased material based upon a customer’s forecast, the Company is usually covered +by lead-time assurance agreements with each customer. These contracts state that the financial liability for material purchased within lead-time and based upon the customer’s forecasts, lies with the customer. If the Company purchases material +outside the lead-time assurance agreement and the customer’s forecasts do not materialize, the Company would have the financial liability and would have to charge the excess against future earnings. +Allowance for Doubtful Accounts : The Company values its accounts receivable net of an +allowance for doubtful accounts. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future, and the amount of this allowance is disclosed in the Company’s Consolidated Balance Sheets. The +estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of +the Company’s customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, the Company could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty : An accrual is made for expected warranty costs, with +the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analysis and anticipated product returns. Over the course of the past three years, the Company’s warranty +expense has decreased. The declines in warranty expense and the related accrual account are directly related to the change in the composition of the Company’s revenue from keyboards to EMS products. As the Company has made the transition from +manufacturing primarily keyboards to primarily EMS products, its exposure to warranty claims has declined significantly. The Company’s warranty period for keyboards is generally longer than that for EMS products. Also the Company does not +warrant design defects for EMS customers. +Goodwill +In July 2001, the Financial Accounting Standards +Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. Under the +statement, the Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. Goodwill will be tested for impairment annually. The Company adopted SFAS No. 142 on June 30, +2002, and completed its impairment test during the second quarters of fiscal years 2004 and 2003. The tests did not indicate an impairment of the Company’s stated goodwill of $765,000. +14 +Table of Contents +The net effect of adopting this accounting standard was to eliminate annual amortization expense of $128,000. In +accordance with SFAS No. 142, the effect of this accounting change is reflected prospectively. Comparative disclosure as if the change had been retroactively applied to fiscal year 2002 is as follows (no tax effect has been included because of +offsetting tax valuations): +Fiscal Years Ended June +2004 +2003 +2002 +(in thousands, except per share data) +Reported net income (loss) +$ +110 +$ +13,409 +$ +(25,362 +) +Add back: goodwill amortization +— +— +128 +Total +$ +110 +$ +13,409 +$ +(25,234 +) +Basic and diluted earnings (loss) per share: +Reported net income (loss) +$ +0.01 +$ +1.39 +$ +(2.62 +) +Goodwill amortization +— +— +.01 +Adjusted basic and diluted earnings (loss) per share +$ +0.01 +$ +1.39 +$ +(2.61 +) +New Accounting Pronouncements +In January 2003, the FASB issued FASB Interpretation No. 46, +“Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46). In December 2003, the FASB issued a revision to FIN 46 to make certain technical corrections and address certain implementation issues that had +arisen. FIN 46, as revised, clarifies existing accounting literature regarding the consolidation of entities in which a company holds a “controlling financial interest”. A majority voting interest in an entity has generally been considered +indicative of a controlling financial interest. FIN 46 specifies other factors (variable interests) which must be considered when determining whether a company holds a controlling financial interest in, and therefore must consolidate, an entity +(variable interest entities). The adoption of FIN 46 had no impact on the Company’s overall financial position and results of operations as the Company has no variable interest entities. +In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative +Instruments and Hedging Activities,” which amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. +This statement is effective for contracts entered into or modified after June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the +Company’s financial statements. +In May 2003, the FASB issued SFAS No. +150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both +liabilities and equity. Financial instruments that are within the scope of the statement, which previously were often classified as equity, must now be classified as liabilities. This statement is effective for financial instruments entered into or +modified after May 31, 2003, and otherwise shall be effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 did not have a material impact on the Company’s financial statements. +In December 2003, the SEC issued Staff Accounting Bulletin No. 104 (SAB 104), +“Revenue Recognition.” SAB 104 supercedes SAB 101, “Revenue Recognition in Financial Statements.” The primary purpose of SAB 104 is to rescind accounting guidance contained in SAB 101 related to multiple element revenue +arrangements, superceded as a result of the issuance of EITF No. 00-21, “Revenue Arrangements with Multiple Deliverables.” Additionally, SAB 104 rescinds the SEC’s “Revenue Recognition in Financial Statements Frequently Asked +Questions and Answers” (“the FAQ”) issued with SAB 101 that had been codified in SEC Topic 13, “Revenue Recognition.” Selected portions of the FAQ have been incorporated into SAB 104. While the wording of SAB 104 has changed +to reflect the issuance of EITF 00-21, the revenue recognition principles of SAB 101 remain largely unchanged by the issuance of SAB 104. The adoption of SAB 104 did not have a material impact on the Company’s financial statements. +15 +Table of Contents +RISKS AND UNCERTAINTIES THAT COULD AFFECT FUTURE RESULTS +The following risks and uncertainties could affect the Company’s actual results and +could cause results to differ materially from past results or those contemplated by the Company’s forward-looking statements. When used herein, the words “expects”, “believes”, “anticipates” and similar expressions +are intended to identify forward-looking statements. +Potential Fluctuations +in Quarterly Results The Company’s quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including changes in overall demand for customers’ products, success of customers’ +programs, timing of new programs, new product introductions or technological advances by the Company, its customers and its competitors and changes in pricing policies by the Company, its customers, its suppliers and its competitors. For example, +the Company relies on customers’ forecasts to plan its business. If those forecasts are overly optimistic, the Company’s revenues and profits may fall short of expectations. Conversely, if those forecasts are too conservative, the Company +could have an unexpected increase in revenues and profits. The products which the Company manufactures for its customers have relatively short product lifecycles, therefore the Company’s business, operating results and financial condition are +dependent in significant part on the Company’s ability to obtain orders from new customers and new product programs from existing customers. +Competition The EMS industry is intensely competitive. Competitors may offer customers lower prices on certain high volume programs. This could result in price +reductions, reduced margins and loss of market share, all of which would materially and adversely affect the Company’s business, operating results and financial condition. The Company’s inability to provide comparable or better +manufacturing services at a lower cost than its competitors could cause sales to decline. In addition, competitors can copy the Company’s non-proprietary designs after the Company has invested in development of products for customers, thereby +enabling such competitors to offer lower prices on such products due to savings in development costs. +Concentration of Major Customers At present, the Company’s customer base is highly concentrated and could become even more concentrated. The Company’s largest EMS customer accounted for 16% of net +sales in fiscal year 2004. This same customer accounted for 31% of sales in 2003 and 39% in 2002. For the fiscal years ended 2004, 2003, and 2002, the five largest customers accounted for 58%, 64% and 85% of total sales, respectively. There can be +no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the +Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and +adversely affect the Company’s business, operating results and financial condition. +Dependence on Suppliers The Company is dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. Delays in +deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect the Company’s operating results +and damage customer relationships. +Dependence on Key Personnel The +Company’s future success depends in large part on the continued service of its key technical, marketing and management personnel and on its ability to continue to attract and retain qualified employees. The competition for such personnel is +intense and there can be no assurance that the Company will be successful in attracting and retaining such personnel. The loss of key employees could have a material adverse effect on the Company’s business, operating results and financial +condition. +Foreign Manufacturing Operations Virtually all +products manufactured by the Company are produced at the Company’s facilities located in Mexico and China. Accordingly, the Company’s operations are subject to a variety of risks unique to international operations including import and +export duties and value added taxes, import and export regulation changes, the burden and cost of compliance with foreign laws and foreign economic and political risk. +Technological Change and New Product Risk The markets for the Company’s customers’ products is characterized by rapidly +changing technology, evolving industry standards, frequent new product introductions and relatively short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing +products obsolete or unmarketable. The Company’s success will depend upon its customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with +technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of the Company’s +16 +Table of Contents +customers to do so could substantially harm the Company’s customers’ competitive positions. There can be no +assurance that the Company’s customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Dilution and Stock Price Volatility As of July 3, 2004, there were outstanding options +for the purchase of approximately 2,072,000 shares of common stock of the Company (Common Stock), of which options for approximately 1,914,000 shares were vested and exercisable. Holders of the Common Stock will suffer immediate and substantial +dilution to the extent outstanding options to purchase the Common Stock are exercised. The stock price of the Company may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be +due to factors specific to the Company such as variations in quarterly operating results or changes in analysts’ earnings estimates, or to factors relating to the EMS and computer industries or to the securities markets in general, which, in +recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company’s major market risk relates to its secured debt. The Company’s debt is secured by substantially +all of the Company’s assets. The interest rates applicable to the Company’s revolving loan fluctuate with the JP Morgan Chase Bank prime rate and LIBOR rates. +The Company does not enter into derivative transactions or leveraged swap agreements. +Although the Company has international operations, the functional currency for all active +subsidiaries is the U.S. dollar. The Company imports for its own use raw materials that are used in its manufacturing operations. Substantially all of the Company’s purchases are denominated in U.S. dollars and are paid under normal trade +terms. +The table below presents principal (or notional) amounts and related +weighted average variable rates by fiscal year of maturity. The weighted average variable interest rates for fiscal years 2004 through 2006 are estimated based on current rates as of August 23, 2004. These forward rates have been increased by +current levels of margins based on the financing agreement with CIT. The Company’s revolving debt could increase or decrease depending upon cash needs over the period of time that the financing agreement remains in place with CIT. The JP Morgan +Chase Bank prime rate and LIBOR will fluctuate with the market and could go up or down depending on market conditions. +Fiscal Years +Total +Fair Value +July 3, 2004 +(In thousands) +2005 +2006 +2007 +Interest rate risk: +Secured revolving debt +$ +10,851 +$ +10,851 +$ +10,851 +Average interest rate +4.56 +% +17 +Table of Contents +Item 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Reports of Independent Registered Public Accounting Firms +The +Board of Directors and Shareholders +Key Tronic Corporation +Spokane, Washington +We have audited the accompanying consolidated +balance sheets of Key Tronic Corporation and subsidiaries (the Company) as of July 3, 2004 and June 28, 2003, and the related consolidated statements of operations, shareholders’ equity and cash flows for the years then ended. We have also +audited the schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on +our audits. +We conducted our audits in accordance with the standards of the +Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements and schedule are free of material misstatement. An audit +includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and schedule. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as +evaluating the overall presentation of the financial statements and schedule. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation and +subsidiaries at July 3, 2004 and June 28, 2003, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the schedule presents fairly, in all material respects, the information +set forth therein. +As discussed in Note 1 to the consolidated financial +statements, the Company changed its method for accounting for goodwill in fiscal 2003. +/s/ BDO Seidman, LLP +Spokane, Washington +August 19, 2004 +18 +Table of Contents +To the Shareholders and Board of Directors of Key Tronic Corporation: +We have audited the accompanying consolidated statements of operations, shareholders’ +equity, and cash flows of Key Tronic Corporation and subsidiaries (the Company) for the year ended June 29, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on +these financial statements based on our audit. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as +well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. +In our opinion, such consolidated financial statements present fairly, in all material respects the results of operations and cash flows of Key Tronic Corporation and +subsidiaries for the year ended June 29, 2002, in conformity with accounting principles generally accepted in the United States of America. +/s/ Deloitte & Touche LLP +Deloitte & Touche LLP +Seattle, Washington +August 16, 2002 +19 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 3, 2004 +June 28, 2003 +ASSETS +Current assets: +Cash and cash equivalents +$ +600 +$ +956 +Trade receivables, less allowance for doubtful accounts of $60 and $105 +24,439 +17,078 +Inventories +27,848 +24,151 +Other +1,833 +2,050 +Total current assets +54,720 +44,235 +Property, plant and equipment, net +11,131 +11,982 +Other assets: +Restricted cash +705 +1,142 +Other, net of accumulated amortization of $696 and $565 +617 +1,001 +Goodwill +765 +765 +Total assets +$ +67,938 +$ +59,125 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +24,354 +$ +13,145 +Accrued compensation and vacation +4,015 +4,213 +Current portion of litigation settlement +925 +1,124 +Current portion of other long-term obligations +606 +730 +Other +1,352 +3,240 +Total current liabilities +31,252 +22,452 +Long-term liabilities: +Revolving loan +10,851 +9,864 +Litigation settlement +1,536 +2,593 +Other long-term obligations +1,065 +1,096 +Total long-term liabilities +13,452 +13,553 +Commitments and contingencies (Notes 4 and 8) +Shareholders’ equity +Common stock, no par value, authorized 25,000 shares; issued and outstanding 9,676 and 9,673 shares, respectively +38,397 +38,393 +Accumulated deficit +(15,163 +) +(15,273 +) +Total shareholders’ equity +23,234 +23,120 +Total liabilities and shareholders’ equity +$ +67,938 +$ +59,125 +See accompanying notes to consolidated +financial statements. +20 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +Years Ended +(In thousands, except per share amounts) +July 3, 2004 +June 28, 2003 +June 29, 2002 +Net sales +$ +148,901 +$ +130,894 +$ +175,591 +Cost of sales +135,664 +115,936 +160,606 +Gross profit on sales +13,237 +14,958 +14,985 +Operating expenses: +Research, development and engineering +2,583 +2,913 +2,554 +Selling +1,900 +2,250 +2,793 +General and administrative +6,965 +7,183 +8,414 +Operating income +1,789 +2,612 +1,224 +Interest expense, net +1,091 +1,026 +1,314 +Litigation (settlement) judgment expense +— +(12,186 +) +20,214 +Other income, net +(23 +) +(237 +) +(358 +) +Income (loss) before income taxes +721 +14,009 +(19,946 +) +Income tax provision +611 +600 +5,416 +Net income (loss) +$ +110 +$ +13,409 +$ +(25,362 +) +Income (loss) per share: +Income (loss) per common share – basic and diluted +$ +0.01 +$ +1.39 +$ +(2.62 +) +Weighted average shares outstanding – basic +9,673 +9,673 +9,673 +Weighted average shares outstanding – diluted +9,793 +9,673 +9,673 +See accompanying notes to consolidated +financial statements. +21 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY +Common Stock +Retained +Earnings/(Deficit) +Accumulated +Other +Comprehensive +Income +Total +(In thousands) +Shares +Amount +Balances, June 30, 2001 +9,673 +$ +38,393 +$ +(3,320 +) +$ +245 +$ +35,318 +Comprehensive income: +Net loss – 2002 +(25,362 +) +(25,362 +) +Other comprehensive income: +Foreign currency translation +(245 +) +(245 +) +Total comprehensive income +(25,607 +) +Balances, June 29, 2002 +9,673 +38,393 +(28,682 +) +— +9,711 +Comprehensive income: +Net income – 2003 +13,409 +13,409 +Balances, June 28, 2003 +9,673 +38,393 +(15,273 +) +— +23,120 +Comprehensive income: +Net income – 2004 +110 +110 +Exercise of stock options +3 +4 +4 +Balances, July 3, 2004 +9,676 +$ +38,397 +$ +(15,163 +) +$ +— +$ +23,234 +See accompanying notes to consolidated +financial statements. +22 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +Years Ended +(In thousands) +July 3, 2004 +June 28, 2003 +June 29, 2002 +Increase (decrease) in cash and cash equivalents: +Cash flows from operating activities: +Net income (loss) +$ +110 +$ +13,409 +$ +(25,362 +) +Adjustments to reconcile net income (loss) to cash provided (used) by operating activities: +Depreciation and amortization +2,957 +3,016 +4,475 +Accretion of deferred gain on sale of building +(78 +) +(78 +) +(78 +) +Provision for obsolete inventory +162 +203 +2,225 +Provision for (recovery of) doubtful receivables +— +(56 +) +175 +Provision for warranty +193 +150 +215 +Litigation judgment (settlement) +— +(12,186 +) +19,479 +(Gain) loss on sale of assets +14 +20 +(559 +) +Deferred income tax provision +— +— +12,866 +Foreign currency translation +— +— +(245 +) +Changes in operating assets and liabilities: +Trade receivables +(7,361 +) +3,956 +521 +Inventories +(3,859 +) +(5,959 +) +(19 +) +Other assets +145 +(22 +) +2,376 +Accounts payable +11,209 +(1,264 +) +(6,976 +) +Accrued compensation and vacation +(198 +) +1,410 +188 +Changes in deferred tax assets +— +— +(8,350 +) +Deferred sales proceeds +— +— +(349 +) +Litigation settlement +(1,256 +) +(3,576 +) +— +Other liabilities +(2,055 +) +433 +337 +Cash provided (used) by operating activities +(17 +) +(544 +) +919 +Cash flows from investing activities: +Purchase of property and equipment +(1,633 +) +(2,128 +) +(1,142 +) +Decrease (increase) in restricted cash +437 +(862 +) +(280 +) +Proceeds from sale of property and equipment and assets held for sale +4 +46 +1,711 +Cash provided (used) by investing activities +(1,192 +) +(2,944 +) +289 +Cash flows from financing activities: +Payment of financing costs +(35 +) +(150 +) +(504 +) +Proceeds from exercise of stock options +4 +— +— +Proceeds from long-term debt +538 +— +— +Repayment of long-term debt +(641 +) +— +— +Borrowing under revolving credit agreement +146,805 +139,000 +177,432 +Repayment of revolving credit agreement +(145,818 +) +(135,611 +) +(179,068 +) +Cash provided (used) by financing activities +853 +3,239 +(2,140 +) +Increase (decrease) in cash and cash equivalents +(356 +) +(249 +) +(932 +) +Cash and cash equivalents, beginning of year +956 +1,205 +2,137 +Cash and cash equivalents, end of year +$ +600 +$ +956 +$ +1,205 +Supplemental cash flow information: +Interest payments +$ +865 +$ +763 +$ +1,340 +Income tax payments, net of refunds +$ +1,015 +$ +348 +$ +1,208 +See accompanying notes to consolidated +financial statements. +23 +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs), and also +manufactures keyboards and other input devices. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly +owned subsidiaries in Ireland, Mexico, and China. Intercompany balances and transactions have been eliminated in consolidation. The Company’s former subsidiaries, KT FSC and Key Tronic Far East Pte Ltd, were legally dissolved on September 5, +2001, and February 22, 2003, respectively. The dissolution of these subsidiaries did not have a material impact on the Company’s financial statements, since the subsidiaries had been inactive for several years. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires +management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses +during the reporting period. Significant estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, the valuation allowances on deferred tax assets, valuation of goodwill, and the provision for +warranty costs. Actual results could differ from those estimates. +Cash +Equivalents +The Company considers investments with an original maturity +of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. +The restricted cash balance includes an approximately $500,000 deposit required by the state of Washington for the Company’s estimated maximum workers’ +compensation liability for the period in which the Company was self-insured. The Company no longer self-insures workers’ compensation liabilities but the deposit will be required to be maintained for a number of years into the future. The +remaining amounts of $205,000 and $642,000 in restricted cash at July 3, 2004 and June 28, 2003, respectively, are amounts in the Company’s bank account that cannot be used for any other purpose than to pay down the Company’s long term +revolving line of credit. +Allowance for Doubtful Accounts +The Company evaluates the collectibility of accounts receivable and records an allowance +for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables that are considered to be impaired based on the Company’s knowledge +of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment, and historical experience. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. The +Company provides for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. +24 +Table of Contents +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected lives of the assets. +Constructed molds and dies are expensed as incurred if there is no future utility beyond one year. Capitalized molds and dies are depreciated over the expected useful lives of one to three years. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and +projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. No assets were +written down during the fiscal years ended July 3, 2004, June 28, 2003, and June 29, 2002. +Deferred Loan Fees +Deferred loan fees +are amortized using the interest method over the term of the related loan agreement. +Accrued Warranty +An accrual is made for expected warranty +costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company began to self-fund its domestic employee health plan on June 30, 2004. The Company contracted a separate administrative service company to supervise and +administer the program and act as representative. The Company also insures for claims exceeding $50,000 and if the aggregate annual claims amount to more than 125% of expected claims for the plan year ending June 30, 2005. We estimate our exposure +for claims incurred but not paid at the end of each reporting period and use historical information supplied by our insurance carrier and broker to estimate our liability for these claims. This liability is subject to a total limitation that varies +based on employee enrollment and factors that are established at each annual contract renewal. Our actual claims experience may differ from our estimates. +Revenue Recognition +Sales revenue from manufacturing is generally recognized upon shipment of the manufactured product under contractual terms, which are generally FOB shipping point. Upon shipment, title transfers and the customer +assumes risks and rewards of ownership of the product. Generally, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at +the time when such requirements are completed and such obligations are fulfilled. +Revenue from engineering design and development services, which are generally performed under contract of short term durations, is recognized as costs are incurred utilizing the percentage-of-completion method. Revenue from engineering +design and development services is less than one percent of total revenue in fiscal years 2004, 2003, and 2002. +Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. Revenue also includes amounts billed to +customers for shipping and handling. +Cost of Sales +Cost of sales includes related shipping and handling costs. Cost of sales for the fiscal +year ending July 3, 2004 includes an insurance settlement recovery of approximately $475,000. +25 +Table of Contents +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed costs of electronic manufacturing services (EMS) as well as design and +engineering costs associated with the production of EMS programs. Such costs are charged to expense as incurred. +Income Taxes +The Company accounts for income taxes in accordance with provisions of Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” Under the asset and liability method +prescribed by SFAS No. 109, deferred income taxes are provided for temporary differences between the financial reporting and tax bases of assets and liabilities. Deferred taxes are measured using provisions of currently enacted tax laws. Tax credits +are accounted for as a reduction of income taxes in the year the credit originates. Determination of the unrecognized deferred tax liability on foreign subsidiary undistributed earnings is not practicable. +Earnings Per Share +Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during +the period. Diluted earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common and common equivalent shares outstanding during the period using the treasury stock method. The computation assumes the +proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per share does not assume conversion, exercise, or contingent issuance of common +stock equivalent shares that would have an antidilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the +Company’s subsidiaries in Ireland, Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses are included in general and administrative expenses. Prior to 2001, assets and liabilities of the Company’s +subsidiary in Ireland had been translated to U.S. dollars at year-end exchange rates. Revenues and expenses had been translated at average exchange rates. Translation gains and losses had been included in a separate component of shareholders’ +equity. The foreign currency translation adjustment of $245,000 as of June 30, 2001, which was included in other comprehensive income, was written off in fiscal year 2002 as a result of the disposal of the majority of the assets of the subsidiary in +Ireland. +Fair Value of Financial Instruments +The carrying values of financial instruments reflected on the balance sheets at July 3, 2004 +and June 28, 2003, reasonably approximate their fair value. Based on the borrowing rates currently available to the Company for loans with similar terms and average maturities, the fair value of long-term debt is estimated to be $10.9 million and +$9.9 million, respectively, as of July 3, 2004 and June 28, 2003, which approximates the carrying values. +Stock-based Compensation +The Company +accounts for its stock-based awards to employees using the intrinsic value method in accordance with Accounting Principles Board No. 25 “Accounting for Stock Issued to Employees” (APB 25). Under APB 25, compensation expense is recognized +only if the option price is less than the quoted market price of the Company’s stock at the date of the option grant. Under SFAS No. 123 “Accounting for Stock Based Compensation”, the fair value of stock-based awards to employees is +calculated through the use of option pricing models. These models require subjective assumptions, including future stock price volatility and expected time to exercise. The Company’s calculations were made using the Black-Scholes option pricing +model with the following weighted average assumptions: expected life, 60 months in 2004 and 2003, and 77 months in 2002; stock volatility, 111.74% in 2004, 107.96% in 2003, and 83.69% in 2002; risk free interest rates, 3.11% in 2004 and 2003, and +3.89% in 2002, and no dividends during the expected term. The weighted average fair values of options granted during fiscal years 2004, 2003, and 2002 were $2.20, $1.16, and $2.07 per share, respectively. +26 +Table of Contents +For purposes of disclosure under SFAS Nos. 123 and 148, the following is the pro forma effect of the options had they +been recorded under the fair value method (no tax effect has been included because of offsetting tax valuations): +Years Ended +July 3, 2004 +June 28, 2003 +June 29, 2002 +(in thousands, except per share information) +Net income (loss), as reported +$ +110 +$ +13,409 +$ +(25,362 +) +Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards +(130 +) +(387 +) +(412 +) +Pro forma net income (loss) +$ +(20 +) +$ +13,022 +$ +(25,774 +) +Earnings (loss) per share: +Basic and diluted – as reported +$ +0.01 +$ +1.39 +$ +(2.62 +) +Basic and diluted – pro forma +$ +(0.00 +) +$ +1.35 +$ +(2.66 +) +Goodwill +In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, +“Goodwill and Other Intangible Assets.” SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. Under the statement, the Company records intangible assets that are acquired individually +or with a group of other assets in the financial statements at acquisition. Goodwill is tested for impairment annually. The Company adopted SFAS No. 142 on June 30, 2002, and completed its impairment test during the second quarter of fiscal 2004 and +2003. The tests did not indicate an impairment of the Company’s stated goodwill of $765,000. +The net effect of adopting this accounting standard was to eliminate annual amortization expense of $128,000. In accordance with SFAS No. 142, the effect of this accounting change is reflected prospectively. +Comparative disclosure as if the change had been retroactively applied to fiscal year 2002 is as follows (no tax effect has been included because of offsetting tax valuations): +Fiscal Years Ended +June +2004 +2003 +2002 +(in thousands, except per share data) +Reported net income (loss) +$ +110 +$ +13,409 +$ +(25,362 +) +Add back: goodwill amortization +— +— +128 +Total +$ +110 +$ +13,409 +$ +(25,234 +) +Basic and diluted earnings (loss) per share: +Reported net income (loss) +$ +0.01 +$ +1.39 +$ +(2.62 +) +Goodwill amortization +— +— +.01 +Adjusted basic and diluted earnings (loss) per share +$ +0.01 +$ +1.39 +$ +(2.61 +) +New Accounting Pronouncements +In January 2003, the FASB issued FASB Interpretation No. 46, +“Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46). FIN 46, as revised, clarifies existing accounting literature regarding the consolidation of entities in which a company holds a “controlling +financial interest”. A majority voting interest in an entity has generally been considered indicative of a controlling financial interest. FIN 46 specifies other factors (variable interests) which must be considered when determining whether a +company holds a controlling financial interest in, and therefore must consolidate, an entity (variable interest entities). The adoption of FIN 46 had no impact on the Company’s overall financial position and results of operations as the Company +has no variable interest entities. +27 +Table of Contents +In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging +Activities,” which amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. This statement is +effective for contracts entered into or modified after June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Company’s financial +statements. +In May 2003, the FASB issued SFAS No. 150, “Accounting for +Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. +Financial instruments that are within the scope of the statement, which previously were often classified as equity, must now be classified as liabilities. This statement is effective for financial instruments entered into or modified after May 31, +2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 did not have a material impact on the Company’s financial statements. +In December 2003, the SEC issued Staff Accounting Bulletin No. 104 (SAB 104), “Revenue +Recognition.” SAB 104 supercedes SAB 101, “Revenue Recognition in Financial Statements.” The primary purpose of SAB 104 is to rescind accounting guidance contained in SAB 101 related to multiple element revenue arrangements, +superceded as a result of the issuance of EITF No. 00-21, “Revenue Arrangements with Multiple Deliverables.” Additionally, SAB 104 rescinds the SEC’s Revenue Recognition in Financial Statements Frequently Asked Questions and Answers +(“the FAQ”) issued with SAB 101 that had been codified in SEC Topic 13, Revenue Recognition. Selected portions of the FAQ have been incorporated into SAB 104. While the wording of SAB 104 has changed to reflect the issuance of EITF 00-21, +the revenue recognition principles of SAB 101 remain largely unchanged by the issuance of SAB 104. The adoption of SAB 104 did not have a material impact on the Company’s financial statements. +Reclassifications +Certain reclassifications of prior balances have been made for consistent presentation with the current year. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2004, 2003, and +2002 ended on July 3, 2004, June 28, 2003, and June 29, 2002, respectively. Fiscal year 2005 will end on July 2, 2005. Fiscal 2004 was a 53 week year and fiscal 2003 and 2002 were 52 week years. +2. INVENTORIES +Components of inventories were as follows: +July 3, 2004 +June 28, 2003 +(in thousands) +Finished goods +$ +10,984 +$ +9,439 +Work-in-process +2,926 +3,117 +Raw materials +17,119 +15,108 +Reserve for obsolescence +(3,181 +) +(3,513 +) +$ +27,848 +$ +24,151 +3. PROPERTY, PLANT AND EQUIPMENT +Life +July 3, 2004 +June 28, 2003 +(in years) +(in thousands) +Land +— +$ +1,730 +$ +1,730 +Buildings and improvements +3 to 30 +11,724 +11,165 +Equipment +1 to 10 +50,187 +67,315 +Furniture and fixtures +3 to 5 +6,412 +6,259 +70,053 +86,469 +Accumulated depreciation +(58,922 +) +(74,487 +) +$ +11,131 +$ +11,982 +28 +Table of Contents +In December of 2000, the Company sold its headquarters building, located in Spokane, Washington. In conjunction with the +sale, the Company entered into a ten year lease agreement for a portion of the building. The gain on the sale of the building was deferred under other long-term obligations and will be amortized to other income over the remaining lease term. +In February of 2002, the Company sold its Cheney, Washington, facility, which +had previously been recorded as real estate held for sale, for $1.7 million, resulting in a gain of $84,000, recorded within other income. +4. LONG-TERM DEBT +The Company has entered into a financing agreement with CIT Group/Business Credit, Inc. (CIT) which provides a revolving credit facility up to $20 million. The revolving loan is secured by the assets of the Company. +The interest rate provisions allow for a variable rate based on either the prime rate or LIBOR rate. The agreement specifies four alternative levels of margin to be added to these base rates depending on compliance with certain financial covenants. +The range of interest being paid to CIT on outstanding balances was 4.34 – 4.75% as of July 3, 2004. The agreement and subsequent amendments contain financial covenants that relate to total equity, earnings before interest, taxes, depreciation +and amortization, and a minimum fixed charge ratio. The revolving loan matures August 23, 2006. As of July 3, 2004, the Company was in compliance with all loan covenants. At July 3, 2004, the outstanding revolving loan balance was $10.9 million +compared to $9.9 million at fiscal year end June 28, 2003. Based on eligible collateral, approximately $9.1 million was available from the revolving line of credit as of July 3, 2004. +5. INCOME TAXES +Income tax expense consists of the following: +Year Ended +July 3, 2004 +June 28, 2003 +June 29, 2002 +(in thousands) +Current income taxes: +Federal +$ +— +$ +(37 +) +$ +— +Foreign +611 +637 +900 +State +— +— +— +611 +600 +900 +Deferred income taxes: +Federal +(464 +) +4,264 +(7,627 +) +Foreign +— +— +— +State +(16 +) +272 +(723 +) +(480 +) +4,536 +(8,350 +) +Change in valuation allowance +480 +(4,536 +) +12,866 +— +— +4,516 +Total income tax expense +$ +611 +$ +600 +$ +5,416 +The Company’s effective tax rate +differs from the federal tax rate as follows: +Year Ended +July 3, 2004 +June 28, 2003 +June 29, 2002 +(in thousands) +Federal income tax expense (benefit) at statutory rates +$ +245 +$ +4,763 +$ +(6,782 +) +Effect of foreign taxes +110 +(101 +) +807 +State tax (net of federal effect) +7 +140 +(723 +) +Permanent differences +Life insurance premiums +65 +65 +50 +Other +(296 +) +269 +(802 +) +Change in valuation allowance +480 +(4,536 +) +12,866 +Income tax provision +$ +611 +$ +600 +$ +5,416 +29 +Table of Contents +The domestic and foreign components of income (loss) before income taxes were: +Year Ended +July 3, 2004 +June 28, 2003 +June 29, 2002 +(in thousands) +Domestic +$ +(709 +) +$ +11,900 +$ +(20,219 +) +Foreign +1,430 +2,109 +273 +Income (loss) before income taxes +$ +721 +$ +14,009 +$ +(19,946 +) +Deferred income taxes result from +temporary differences in the timing of recognition of revenue and expenses. Deferred income tax assets and liabilities consist of the following at: +July 3, 2004 +June 28, 2003 +(in thousands) +Allowance for doubtful accounts +$ +18 +$ +32 +Inventory +1,675 +1,462 +Vacation accrual +342 +346 +Warranty accrual +59 +55 +State deferred asset +72 +71 +Litigation judgment (current portion) +315 +382 +Other +19 +132 +Current deferred income tax assets +2,500 +2,480 +Current portion of valuation allowance +(2,500 +) +(2,480 +) +Current deferred income tax assets, net of valuation allowance +$ +— +$ +— +Depreciation and amortization +$ +22 +$ +686 +State deferred taxes +615 +600 +Litigation judgment (non-current portion) +522 +882 +Net operating loss carryforwards +19,971 +18,396 +Tax credit carryforwards +536 +607 +Other +434 +469 +Noncurrent deferred income tax assets +22,100 +21,640 +Valuation allowance, net of current portion +(22,100 +) +(21,640 +) +Noncurrent deferred income tax assets, net of valuation allowance +$ +— +$ +— +Total deferred income tax assets +$ +— +$ +— +SFAS No. 109 requires that management +assess the sources of future taxable income, which may be available to recognize the deductible differences that comprise deferred tax assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or +all of the deferred tax assets will not be realized. Management has determined that a valuation allowance equal to the net deferred tax assets is appropriate. +At July 3, 2004, the Company had net operating loss carryforwards approximating $59 million. The net operating loss carryforwards expire in varying amounts from fiscal +years ending in 2006 through 2024. The Company also has general business credits and alternative minimum tax credits approximating $316,000 and $220,000, respectively. The general business credits expire in varying amounts from fiscal years ending +in years 2005 through 2009 and the alternative minimum tax credits do not expire. Utilization of net operating loss carryforwards would be limited in the event the Company’s ownership changes more than 50% in a three-year period. +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (loss) (the numerator) by the weighted-average number of common shares +outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents. The following table presents a reconciliation of the denominator +and the number of antidilutive common share options that were not included. These antidilutive securities occur when options outstanding have an option price greater than the average market price for the period. +30 +Table of Contents +Fiscal Years Ending +2004 +2003 +2002 +Total weighted average shares – basic +9,673,128 +9,672,580 +9,672,580 +Effect of dilutive common stock options +119,707 +— +— +Total weighted average shares – diluted +9,792,835 +9,672,580 +9,672,580 +Antidilutive options not included in diluted earnings per share +1,952,184 +2,086,086 +2,081,304 +7. STOCK OPTION AND BENEFIT PLANS +The Company has executive stock option plans for certain key employees. +Options under these plans vest over one to five years and become exercisable as they vest. Options under the plans become exercisable in full immediately prior to the occurrence of a “Change in Control” as defined in the plan documents. +The Company has reserved 2,795,000 shares for issuance under these plans. As of July 3, 2004, 1,826,891 options were outstanding of which 1,728,554 shares were exercisable. There are 112,467 shares available for future grant under these option +plans. These options expire ten years from the date of grant. +The Company also +has a stock option plan for “Nonemployee Directors.” Options under this plan vest over a three-year period and are exercisable as they vest. The Company has reserved 300,000 shares for issuance under this plan. As of July 3, 2004, 245,000 +options were outstanding of which 185,416 shares were exercisable. There are 24,650 shares available for future grant under this plan. These options expire ten years from the date of grant. +Compensation expense for options will be recorded if the exercise price of the option is less +than the closing market price of the stock on the date of grant. There was no compensation expense incurred in conjunction with options issued in fiscal years 2004, 2003, or 2002, as all options were granted at fair market value. See Note 1 for the +pro forma effect if the Company had accounted for the stock options using fair value methods. +Following is a summary of plan activity: +Price Range +Number +Of Options +Weighted Average +Exercise Price +Outstanding, June 30, 2001 +$ +1.54 to $16.25 +1,966,200 +$ +4.99 +Granted during 2002 +$ +2.00 to $ 2.11 +130,000 +$ +2.07 +Expired or canceled +$ +2.75 to $7.25 +(14,896 +) +$ +4.12 +Outstanding, June 29, 2002 +$ +1.54 to $16.25 +2,081,304 +$ +4.81 +Granted during 2003 +$ +1.15 to $ 1.20 +160,000 +$ +1.16 +Expired or canceled +$ +1.15 to $16.25 +(155,218 +) +$ +6.04 +Outstanding, June 28, 2003 +$ +2.75 to $16.25 +2,086,086 +$ +4.44 +Granted during 2004 +$ +2.20 +37,500 +$ +2.20 +Exercised +$ +1.15 +(3,333 +) +$ +1.15 +Expired or canceled +$ +1.15 to $ 9.50 +(48,362 +) +$ +7.62 +Outstanding, July 3, 2004 +$ +1.15 to $16.25 +2,071,891 +$ +4.33 +31 +Table of Contents +Additional information regarding options outstanding as of June 28, 2003, is as follows: +Options +Outstanding +Options +Exercisable +Range of +Exercise Prices +Number +Outstanding +Weighted Avg. +Remaining +Contractual +Life (yrs.) +Weighted +Avg. Exercise +Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$ 1.15 - $ 1.73 +145,000 +6.0 +$ +1.18 +57,914 +$ +1.20 +$ 1.74 - $ 2.60 +167,500 +6.1 +$ +2.10 +96,665 +$ +2.06 +$ 2.61 - $ 3.92 +789,000 +6.4 +$ +2.79 +789,000 +$ +2.79 +$ 3.93 - $ 5.89 +685,200 +4.9 +$ +5.07 +685,200 +$ +5.07 +$ 5.90 - $ 8.85 +198,191 +4.0 +$ +7.43 +198,191 +$ +7.43 +$ 8.86 - $13.30 +20,000 +0.3 +$ +10.75 +20,000 +$ +10.75 +$13.31 - $16.25 +67,000 +2.6 +$ +16.25 +67,000 +$ +16.25 +$ 1.15 - $16.25 +2,071,891 +5.5 +$ +4.33 +1,913,970 +$ +4.56 +The Company’s defined +contribution plan is available to U.S. employees who have attained age 21. The Company contributes an amount equal to 100% of the employee’s contribution on the first 3% of the employee’s compensation and an additional 50% of the +employee’s contribution on the following 2% of the employee’s compensation. Company contributions to the plan were $370,336, $366,190, and $362,458 in fiscal years 2004, 2003 and 2002, respectively. +8. COMMITMENTS AND CONTINGENCIES +Leases: The Company has operating leases for certain equipment and production +facilities, which expire at various dates during the next seven years. Future minimum payments under non-cancelable operating and capital leases with initial or remaining terms of one year or more at July 3, 2004, are summarized as follows (in +thousands): +Fiscal Years Ending +Operating +Leases +Capital +Leases +2005 +$ +2,802 +$ +371 +2006 +1,833 +63 +2007 +862 +6 +2008 +448 +6 +2009 +440 +5 +Thereafter +700 +— +Total minimum lease payments +$ +7,085 +451 +Amount representing interest +(59 +) +Present value of lease payments +392 +Current portion +(324 +) +Capital lease obligations, net of current portion +$ +68 +As of July 3, 2004, the gross carrying +amount of the Company’s equipment financed under capital leases amounted to approximately $538,000. Accumulated depreciation for property and equipment under capital leases totaled approximately $78,000. The weighted average interest rate on +these capital leases is approximately 8.50% and expire at various dates through fiscal year 2009. +Rental expenses under operating leases were approximately $4.4 million, $4.6 million, and $4.5 million in 2004, 2003, and 2002, respectively. +Warranty Costs: The Company provides warranties on certain product sales and allowances for estimated warranty costs are recorded +during the period of sale. The determination of such allowances requires us to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company currently establishes warranty reserves based +on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. +32 +Table of Contents +If actual return rates and/or repair and replacement costs differ significantly from our estimates, adjustments to +recognize additional cost of sales may be required in future periods. +Components of the reserve for warranty costs during 2004, 2003, and 2002 were as follows: +Balance at June 30, 2001 +$ +326,545 +Additions related to current period sales +215,101 +Warranty costs incurred in the current period +(247,376 +) +Balance at June 29, 2002 +294,270 +Additions related to current period sales +150,000 +Warranty costs incurred in the current period +(283,126 +) +Balance at June 28, 2003 +161,144 +Additions related to current period sales +192,715 +Warranty costs incurred in the current period +(180,127 +) +Balance at July 3, 2004 +$ +173,732 +Litigation : On December 20, +2001, a jury in Seattle federal court rendered a verdict in the case of F&G Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic Corporation, United States District Court for the +Western District of Washington, Case No. C99-995C (the “litigation”) finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury awarded damages to the Plaintiffs in the amount +of $16.5 million. The judgment against the Company was subsequently increased to approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a settlement of the litigation with the Plaintiffs +(hereafter called “F&G”). Under the terms of the settlement, the Company has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G of $2.5 million, as well as make quarterly +payments to F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is greater, until the total payment of $7.0 million has been made, provided the total payment is completed by December 15, 2005. The remaining amount to be paid +of the $7.0 million settlement was approximately $2.5 million at July 3, 2004. +If the total of $7.0 million is not paid by 12/15/2005, the total settlement amount increases on 12/15/2005 to $7.6 million. If payment of $7.6 million is not completed by 12/15/2006 the total settlement amount increases to $8.2 million. If +payment of $8.2 million is not completed by 12/15/2007 the total settlement amount increases to $8.8 million. If payment of $8.8 million is not completed by 12/15/2008 the total settlement amount increases to $9.7 million. If payment of $9.7 million +is not completed by 12/15/2009 the total settlement amount increases to $10.6 million. If payment of $10.6 million is not made by 12/15/2010 the total settlement amount increases to $11.5 million. Any unpaid balance remaining at 12/15/2011 will +accrue interest thereafter at prime plus 1½% per annum until paid. If the Company fails to make any minimum quarterly payment when due, Plaintiffs have the right to accelerate all remaining payments in the amount of $11.5 million less any +amounts previously paid. +Reported earnings for the fiscal year ended June 28, +2003, include a one-time benefit of $12.2 million ($1.26 per share) for a revision of the litigation accrual. +On March 31, 2004 a former employee of the Company filed a complaint against the Company in the Superior Court of the State of Washington, Spokane County. Anthony DeStefano, Jr. v Key Tronic Corporation , Case +No. 04201480-2. The complaint asserted claims for breach of contract, wrongful withholding of wages and wrongful discharge and sought an unspecified amount of damages. The complaint was dismissed with prejudice in September 2004 with each party +bearing its own costs. +The Company is party to certain other lawsuits or +claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Also see Note 8 to the +Consolidated Financial Statements. +33 +Table of Contents +9. ENTERPRISE-WIDE DISCLOSURES +Management organizes its business around EMS and keyboards based on geographic area. These businesses have been aggregated into one segment +as each has similar economic characteristics, and the nature of the business, its production processes, customers and distribution methods are similar. +Of the revenues for the years ended July 3, 2004, June 28, 2003, and June 29, 2002, EMS sales were $135.5 million, $116.0 million, and $157.0 million, respectively. +Keyboard sales for the years ended July 3, 2004, June 28, 2003, and June 29, 2002 were $12.9 million, $14.6 million, and $18.3 million, respectively. The remainder of revenues for all years presented were from sales of miscellaneous other products +and services. +Net sales and long-lived assets (property, plant, and equipment) +by geographic area for the years ended July 3, 2004, June 28, 2003, and June 29, 2002 are summarized in the following table. Net sales set forth below are based on the shipping destination. +Domestic (U.S.) +Foreign +Total +(in thousands) +2004 +Net sales +$ +134,413 +$ +14,488 +$ +148,901 +Long-lived assets +$ +10,153 +$ +978 +$ +11,131 +2003 +Net sales +$ +114,674 +$ +16,220 +$ +130,894 +Long-lived assets +$ +10,974 +$ +1,008 +$ +11,982 +2002 +Net sales +$ +143,324 +$ +32,267 +$ +175,591 +Long-lived assets +$ +11,429 +$ +803 +$ +12,232 +For the year ended July 3, 2004, 44.5% +of the Company’s foreign net sales were to customers in Mexico, 29.7% were to customers in Europe, 20.1% were to customers in Canada, and the remaining 5.7% were spread among customers in Asia and South America. +For the year ended June 28, 2003, 71.7% of the Company’s foreign net sales were to +customers in the Far East, 14.6% were to customers in Mexico, 10.0% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +For the year ended June 29, 2002, 45.4% of the Company’s foreign net sales were to customers in Mexico, 44.3% were to customers in the +Far East, 6.6% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +Significant Customers +The following customers accounted for 10% or more of consolidated revenues in the three fiscal years presented below: +Fiscal Year +2004 +2003 +2002 +The Clorox Company +16 +% +31 +% +39 +% +Lexmark International, Inc. +14 +% +8 +% +18 +% +Zebra Technologies Corporation +12 +% +8 +% +0 +% +Transaction Printer Group, Inc. +10 +% +9 +% +10 +% +Hewlett-Packard Company +1 +% +8 +% +13 +% +Accounts receivable related to The +Little Tikes Company, Lexmark International, Inc., and Transaction Printer Group, Inc. represented approximately 19%, 13%, and 12%, respectively of the Company’s total accounts receivable balance as of July 3, 2004. Sales to The Little Tikes +Company did not account for more than 10% of consolidated revenues in fiscal year 2004 as sales did not commence until the latter part of the year. +34 +Table of Contents +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company +at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or +more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +10. QUARTERLY FINANCIAL DATA +(Unaudited) +Year Ended July 3, 2004 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +34,652 +$ +32,567 +$ +37,316 +$ +44,366 +Gross profit +$ +3,355 +$ +2,672 +$ +3,652 +$ +3,558 +Income (loss) before income taxes +$ +193 +$ +(177 +) +$ +350 +$ +355 +Net income (loss) +$ +20 +$ +(287 +) +$ +112 +$ +265 +Earnings (loss) per common share basic and diluted +$ +0.00 +$ +(0.03 +) +$ +0.01 +$ +0.03 +Weighted average shares +Basic +9,673 +9,673 +9,673 +9,675 +Diluted +9,775 +9,673 +9,793 +10,007 +Year Ended June 28, 2003 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +34,034 +$ +30,552 +$ +30,645 +$ +35,663 +Gross profit +$ +3,506 +$ +3,484 +$ +3,778 +$ +4,190 +Income before income taxes +$ +12,718 +$ +190 +$ +320 +$ +781 +Net income +$ +12,479 +$ +74 +$ +306 +$ +550 +Earnings per common share basic and diluted +$ +1.29 +$ +.01 +$ +.03 +$ +.06 +Weighted average shares +Basic +9,673 +9,673 +9,673 +9,673 +Diluted +9,673 +9,673 +9,675 +9,714 +35 +Table of Contents +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL +DISCLOSURES +On December 3, 2002 Deloitte & Touche, LLP (“D&T”) was dismissed as the Company’s independent public accountants and BDO Seidman, LLP (“BDO”) was appointed as the Company’s new +independent accountants to replace D&T for the fiscal year ending June 28, 2003. The decision to dismiss D&T and to appoint BDO was made and approved by the Audit Committee. D&T’s reports on the Company’s financial statements +for the past two fiscal years did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the prior two fiscal years and through December 3, 2002, +there were no disagreements with D&T on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of D&T would have caused that +firm to make reference to the subject matter of the disagreements in connection with its reports; and there were no reportable events as defined in certain SEC regulations. Prior to the engagement of BDO the Company had not consulted with BDO during +the prior two fiscal years and through December 3, 2002 in any matter regarding the application of accounting principles on a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the +Company’s financial statements, or any other matters or reportable events as defined in certain SEC regulations. See Form 8-K dated December 3, 2002. +Item 9A: CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no changes in the Company’s internal controls over financial reporting during the quarter ended July 3, 2004 that have materially affected, or are reasonable +likely to materially affect, the Company’s internal control over financial reporting. +Item 9B: OTHER INFORMATION +None +36 +Table of Contents +PART III +Item 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +DALE F. PILZ – Director, Chairman of the Board +Dale F. Pilz, age 78, has served as Chairman of the Board since January 2000 and has been a director of the Company since April 1992. Mr. Pilz was Chief Executive Officer of Flowind Corporation from 1986 to 1990. He +served as President of Omninet Corporation from 1985 to 1986. Prior to that, Mr. Pilz was Chief Executive Officer and President of GTE Sprint Communications from 1983 to 1985 and also served as Chief Executive Officer and President of GTE Spacenet +Corporation from 1983 to 1985. +WENDELL J. SATRE - Director +Wendell J. Satre, age 86, has been a director of the Company since 1988 and +served as Chairman of the Board of Directors from July 1991 through August 1995. Mr. Satre also served as a director from 1983 through 1986 and served as President and CEO of the Company from August 1991 through February 1992. Mr. Satre is the +retired Chairman of the Board and Chief Executive Officer of the Washington Water Power Company (now Avista Corp.), a public utility headquartered in Spokane Valley, Washington. Mr. Satre also serves on the Board of Directors of Output Technology +Corporation and The Coeur d’Alenes Company. +YACOV A. SHAMASH +- Director +Yacov A. Shamash, age 54, has been a director of the +Company since 1989. He has been the Dean of Engineering and Applied Sciences at the State University of New York campus at Stony Brook since 1992. Professor Shamash developed and directed the NSF Industry/University Cooperative Research Center for +the Design of Analog/Digital Integrated Circuits from 1989 to 1992 and also served as Chairman of the Electrical and Computer Engineering Department at Washington State University from 1985 until 1992. Dr. Shamash also serves on the Board of +Directors of American Medical Alert Corp, Manchester Technologies Inc. and Netsmart Technologies, Inc. +WILLIAM E. TERRY - Director +William E. Terry, age 71, has been a director of the Company since August 1992. Mr. Terry retired from Hewlett-Packard in November 1993 where he served in a number of executive positions during the prior 36 years. He is a Trustee of Santa +Clara University and also serves on the Board of Directors of Altera Corporation. +PATRICK SWEENEY - Director +Patrick Sweeney, age 69, has been a director of the Company since July 2000. Mr. Sweeney was President and CEO of Hadco Corporation from 1991 through 1995 and formerly served as Hadco’s Vice President/Chief Financial Officer and Vice +President of Operations. Prior to that Mr. Sweeney was the Vice President of International Manufacturing at Wang - USA from 1981 through 1986 and also served as Managing Director of Ireland for Wang and as Plant Manager of its Galway and Clonmel +divisions. Mr. Sweeney also serves on the Board of Directors of Aimware, Info. Mosaic, Photo Machining Inc. and Farran Technologies. +JACK W. OEHLKE - Director, President and Chief Executive Officer +Jack W. Oehlke, age 58, has been President and Chief Executive Officer of the Company since June 1997. From October 1995, he served as Chief +Operating Officer. Previously, he served as Senior Vice President of Operations from January 1995 to October 1995 and Vice President of Manufacturing Operations of the Company from December 1993 to January 1995. Mr. Oehlke served as Director of +Operations, Director of Quality and in various management positions within manufacturing, engineering and quality functions of the Microswitch Division of Honeywell, Inc. from 1968 to 1993. Mr. Oehlke has a Bachelor of Science Degree in Industrial +Technology from the University of Wisconsin at Menomonie. +RONALD F. +KLAWITTER - Executive Vice President of Administration and Chief Financial Officer +Mr. Klawitter, age 52, has been Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary and Treasurer of the Company since October 1995. +He was Acting Secretary from +37 +Table of Contents +November 1994 to October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, +Mr. Klawitter was Vice President, Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. He has a BA degree from Wittenberg University and is a Certified Public Accountant. +CRAIG D. GATES - Executive Vice President and General Manager +Mr. Gates, age 45, has been Executive Vice President and General Manager +since August 2002. Previously he was Executive Vice President of Marketing, Engineering and Sales since July 1997. He served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as +Vice President of Engineering in October of 1994. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. From 1982 he held various engineering and +management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. +EFREN R. PEREZ – Vice President of S.W. Operations +Mr. Perez, age 64, has served as Vice President of S.W. Operations since July 1997. +Previously he was the Managing Director of S.W. Operations from July 1996 to July 1997 and Director of S.W. Operations from July 1995 to June 1996. Following the Company’s acquisition of the Honeywell, Inc. Keyboard Division, Mr. Perez served +as Plant Manager in Juarez from July 1993 to July 1995. He served as Plant Manager in Juarez for the Keyboard Division of Honeywell, Inc. from February 1989 to July 1993. Mr. Perez is a graduate of the University of Mexico with a B.S. in +Physics. +MICHAEL D. CHARD – Vice President of Materials +Mr. Chard, age 46, has been Vice President of Materials of the Company +since July 28, 2000. From February 1999 to July 28, 2000, he held various management positions with the Company in planning, quality assurance, and materials. From January 1997 to January 1999, he was Vice President of Product Delivery at Wang +Global and its predecessor Olivetti North America. From 1983 to 1996, he held various management positions in finance, marketing, and operations at ISC Systems, the predecessor to Olivetti North America. He holds a BA Degree in Business and +Accounting from Washington State University and is a Certified Public Accountant. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2003 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors +has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its +website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information +appearing under the caption “Executive Compensation” in the Company’s 2004 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 3, 2004. +38 +Table of Contents +EQUITY COMPENSATION PLAN INFORMATION +Plan category +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 reflected in +column (a)) +(c) +Equity compensation plans approved by security holders +1,692,391 +$ +4.78 +91,617 +Equity compensation plans not approved by security holders (1) +379,500 +$ +2.33 +45,500 +Total +2,071,891 +$ +4.33 +137,117 +(1) +Consists of the Key Tronic Corporation 2000 Employee Stock Option Plan +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2004 Proxy Statement is incorporated +herein by this reference. +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in the Company’s 2004 Proxy Statement is incorporated herein by this +reference. +Item 14: PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2004 Proxy Statement is incorporated herein by this reference. +39 +Table of Contents +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in +Form 10-K +FINANCIAL STATEMENTS +Reports of Independent Registered Public Accounting Firms +18-19 +Consolidated Balance Sheets, as of July 3, 2004, and June 28, 2003 +20 +Consolidated Statements of Operations for the years ended July 3, 2004, June 28, 2003, and June 29, 2002 +21 +Consolidated Statements of Shareholders’ Equity for the years ended July 3, 2004, June 28, 2003, and June 29, 2002 +22 +Consolidated Statements of Cash Flows for the years ended July 3, 2004, June 28, 2003, and June 29, 2002 +23 +Notes to Consolidated Financial Statements +24-35 +2. SCHEDULES +Independent Auditors’ Report on Financial Statement Schedule II. +18, Exhibit 23.2 +Consolidated Valuation and Qualifying Accounts +42 +Other schedules are omitted because of +the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages +14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Employment Contract with Michael D. Chard, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended July 1, 2000 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.8* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.9* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.10 +Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended September 29, 2001 +10.11 +First and Second Amendments to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 29, +2002 +40 +Table of Contents +10.12 +Third Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 29, +2002 +10.13 +Fourth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 28, +2003 +10.14 +Fifth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 27, +2003 +10.15 +Sixth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended April 3, +2004 +10.16 +Seventh Amendment to Financing Agreement with CIT Group Business Credit, Inc., submitted herewith +10.17 +Eighth Amendment to Financing Agreement with CIT Group Business Credit, Inc., submitted herewith +14. +Code of Conduct, submitted herewith +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +23.2 +Consent of Independent Registered Public Accounting Firm and Report on Schedule, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +* +Management contract or compensatory plan or arrangement +41 +Table of Contents +PART IV +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING +ACCOUNTS +FISCAL YEARS ENDED JULY 3, 2004, JUNE 28, 2003, AND +JUNE 29, 2002 +2004 +2003 +2002 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +3,513 +$ +4,765 +$ +2,712 +Provisions +162 +203 +2,225 +Dispositions +(494 +) +(1,455 +) +(172 +) +Balance at end of year +$ +3,181 +$ +3,513 +$ +4,765 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +105 +$ +444 +$ +633 +(Recovery) provisions +— +(56 +) +175 +Write-offs +(45 +) +(283 +) +(364 +) +Balance at end of year +$ +60 +$ +105 +$ +444 +42 +Table of Contents +SIGNATURES +Pursuant to the +requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 17, 2004 +KEY TRONIC CORPORATION +By: +/s/ Jack W. Oehlke +Jack W. Oehlke, Director, President, +and Chief Executive Officer +43 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by +the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Jack W. Oehlke +September 17, 2004 +Jack W. Oehlke +Date +(Director, President and +Chief Executive Officer) +/s/ Ronald F. Klawitter +September 17, 2004 +Ronald F. Klawitter +Date +(Principal Financial Officer) +/s/ Dale F. Pilz +September 17, 2004 +Dale F. Pilz +Date +(Director, Chairman of the Board) +/s/ Wendell J. Satre +September 17, 2004 +Wendell J. Satre +Date +(Director) +/s/ Yacov A. Shamash +September 17, 2004 +Yacov A. Shamash +Date +(Director) +/s/ Patrick Sweeney +September 17, 2004 +Patrick Sweeney +Date +(Director) +/s/ William E. Terry +September 17, 2004 +William E. Terry +Date +(Director) +44 \ No newline at end of file diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/filing_metadata.csv b/raw/filings/0000719733/2004/0001193125-04-157946/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..bd79aa6eeae73ce1350d4f4d9cf23f1b90c34448 --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2004-09-17,2004-07-03,2004-09-17T15:04:06.000Z,0001193125-04-157946,d10k.htm,"FOR THE FISCAL YEAR ENDED JULY 3, 2004",828965,0,0,https://www.sec.gov/Archives/edgar/data/719733/000119312504157946/d10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000119312504157946/,2004,2004,1 diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/item1.txt b/raw/filings/0000719733/2004/0001193125-04-157946/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..275e4be9a3d21148f18c20e91a462865d8c6c3ea --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/item1.txt @@ -0,0 +1,172 @@ +Item 1. BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, +and its subsidiaries (hereinafter collectively called the “Company”, “Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related +products manufacturing for original equipment manufacturers (OEMs). The Company also manufactures keyboards and other input devices for personal computers, terminals, and workstations primarily in standard layouts that can be sold directly from +inventory on hand. +Presently, Key Tronic is known as an independent provider +of product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing its strengths and capabilities, the Company shifted its focus to electronic +manufacturing services (EMS). +Operations are currently conducted in facilities +in the United States, China, Mexico, and Ireland. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs and reduced +product fulfillment time. +The EMS industry is comprised of companies that +provide a range of manufacturing services for OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to outsourcing manufacturing, and this trend is expected to continue in the future. +Marketing +The Company provides manufacturing services for outsourced OEM products. Key Tronic provides a mix of EMS services including: product +design, surface mount technologies (SMT) for printed circuit assembly, tool making, precision molding, liquid plastic injection molding, prototype design, full box builds, and printing screened silver flexible circuit membranes. +The percentage of revenues from EMS services for the fiscal years ended July 3, 2004, June +28, 2003, and June 29, 2002 were 91.1%, 88.6%, and 89.4%, respectively. Sales of such products have historically not been seasonal in nature, but may be seasonal in the future, due to changes in the types of products manufactured. +The following customers accounted for 10% or more of consolidated revenues in the three +fiscal years presented below: +Fiscal Year +2004 +2003 +2002 +The Clorox Company +16 +% +31 +% +39 +% +Lexmark International, Inc. +14 +% +8 +% +18 +% +Zebra Technologies Corporation +12 +% +8 +% +0 +% +Transaction Printer Group, Inc. +10 +% +9 +% +10 +% +Hewlett-Packard Company +1 +% +8 +% +13 +% +For the fiscal years ended July 3, +2004, June 28, 2003, and June 29, 2002, the five largest customers in each year accounted for 58%, 64%, and 85% of total sales, respectively. +3 +Table of Contents +Although keyboard manufacturing is still included in the Company’s product offerings, annual keyboard sales continue +to decline. During the fiscal years ended July 3, 2004, June 28, 2003, and June 29, 2002, the Company realized revenues of approximately $12.9 million, $14.6 million, and $18.3 million, respectively, from the sale of keyboards representing +approximately 8.7%, 11.1%, and 10.4% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the demand for standard products, the Company maintains a purchase-from-stock +program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original system-supplied keyboards. +The Company markets its products and services primarily through its direct sales department +aided by strategically located field sales people and distributors. Although the Company established relationships with several independent sales organizations to assist in marketing the Company’s EMS product lines in the U.S., commissions +earned and paid are insignificant. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding an +extensive capital equipment base to achieve selective vertical integration in its manufacturing processes. The Company has invested significant capital into surface mount technologies (SMT) for high volume manufacturing of complex printed circuit +board assemblies. The Company designs and develops tooling for injection molding machines and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the Company has invested in equipment to produce printed +flexible circuit membranes. +Key Tronic uses a variety of manual and highly +automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, SMT, flexible robotic assembly, computerized vision system quality inspection, automated +switch and keytop installation, and automated functional testing. +The +Company’s automated manufacturing processes enable it to work closely with its customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. Key Tronic uses +computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround time during product development. +The Company purchases materials and components for its products from many +different suppliers both domestic and international. Key Tronic develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas as of and for the years ended +July 3, 2004, June 28, 2003, and June 29, 2002 is summarized in the following table. Net sales provided below are based on the shipping destination. +Domestic (U.S.) +Foreign +Total +(in thousands) +2004 +Net sales +$ +134,413 +$ +14,488 +$ +148,901 +Long-lived assets +$ +10,153 +$ +978 +$ +11,131 +2003 +Net sales +$ +114,674 +$ +16,220 +$ +130,894 +Long-lived assets +$ +10,974 +$ +1,008 +$ +11,982 +2002 +Net sales +$ +143,324 +$ +32,267 +$ +175,591 +Long-lived assets +$ +11,429 +$ +803 +$ +12,232 +For the year ended July 3, 2004, 44.5% +of the Company’s foreign net sales were to customers in Mexico, 29.7% were to customers in Europe, 20.1% were to customers in Canada, and the remaining 5.7% were spread among customers in Asia and South America. +For the year ended June 28, 2003, 71.7% of the Company’s foreign net sales were to +customers in the Far East, 14.6% were to customers in Mexico, 10.0% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +4 +Table of Contents +For the year ended June 29, 2002, 45.4% of the Company’s foreign net sales were sold to customers in Mexico, 44.3% +were to customers in the Far East, 6.6% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +Backlog +At August 1, 2004, the Company had an order backlog of approximately $68.1 million. This compares with a backlog of approximately $34.9 million at August 2, 2003. Order backlog is not necessarily indicative of future +sales but can be indicative of trends in expected future sales revenue. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next fiscal year, although shipment dates are subject to change +due to design modifications, customer forecast changes, or other customer requirements. +Research, Development, and Engineering +Research and +development and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. The Company’s RD&E +expenses were $2.6 million, $2.9 million, and $2.6 million in fiscal years 2004, 2003, and 2002, respectively. In fiscal years 2004, 2003, and 2002, the Company focused most of its RD&E efforts on current customer EMS programs. The higher cost +in fiscal year 2003 compared to fiscal years 2004 and 2002 is due primarily to a 10% pay reduction during most of fiscal years 2004 and 2002. Part of the increase in 2003 was due to a decrease in the amounts charged to the Company’s customers. +Competition +The market for the products and services the Company provides is highly competitive. There +are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and +price. +Trademarks and Patents +The Company owns several keyboard patents; however, since the Company’s current focus +is electronic manufacturing services, management believes that these patents will not have a significant impact on future revenues. The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets +of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS Co.” to better identify its primary business concentration. +Employees +As of July 3, 2004, the Company had approximately 2,847 employees compared to 2,687 on June 28, 2003 and 1,995 on June 29, 2002. The increase in employees is due +primarily to additional production workers hired in the Company’s Juarez facility to ramp-up for more labor intensive customer programs. The Company can have significant fluctuations in product demand. The Company seeks to maintain flexibility +in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition to full-time employees. The Company’s employees in Reynosa, Mexico, are represented by local unions. The Company has no +history of any material interruption of production due to labor disputes. +The +Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The Company’s employee benefits include bonus programs involving periodic payments to all employees based on meeting +quarterly or fiscal year before-tax income targets. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% on a portion of the employee’s contribution, and also provides group health, +life, and disability insurance plans. The Company also maintains stock option plans for certain employees and outside directors. +5 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/item13.txt b/raw/filings/0000719733/2004/0001193125-04-157946/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..63b3208de6b1adc661778fe57bc04725f181e9b8 --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/item13.txt @@ -0,0 +1,3 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in the Company’s 2004 Proxy Statement is incorporated herein by this +reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/item9a.txt b/raw/filings/0000719733/2004/0001193125-04-157946/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b49f4851bb41061b79bb9ccd02426cd5ea87d714 --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/item9a.txt @@ -0,0 +1,8 @@ +Item 9A: CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no changes in the Company’s internal controls over financial reporting during the quarter ended July 3, 2004 that have materially affected, or are reasonable +likely to materially affect, the Company’s internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/rp_note.txt b/raw/filings/0000719733/2004/0001193125-04-157946/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2004/0001193125-04-157946/rpt_disclosure.txt b/raw/filings/0000719733/2004/0001193125-04-157946/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ac54b426f10b010516d3fb04d988af7cdaf4444f --- /dev/null +++ b/raw/filings/0000719733/2004/0001193125-04-157946/rpt_disclosure.txt @@ -0,0 +1,14 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +See Compensation Committee Interlocks and Insider Participation in Compensation Decisions, page 10. +In October 2002, the Board of Directors approved retention bonus plans for Messrs. Oehlke, Gates and Klawitter. Under the retention bonus plan, Mr. Oehlke became eligible +to receive retention bonus payments in August of 2003, 2004 and 2005, if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts under Mr. Oehlke’s retention bonus plan are +$211,250 for 2003, $243,750 for 2004 and $276,250 for 2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Oehlke pursuant to any Company incentive plans during the fiscal year immediately +preceding the retention bonus payment date. +Under the retention bonus plan, +Mr. Gates became eligible to receive on the payment date retention bonus payments in August of 2003, 2004 and 2005 if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts +under Mr. Gates retention bonus plan are $119,000 for 2003, $142,800 for 2004 and $166,600 for 2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Gates pursuant to any Company incentive +plans during the fiscal year immediately preceding the retention bonus payment date. +13 +Under the retention bonus plan, Mr. Klawitter became eligible to receive retention bonus payments in August of 2003, 2004 +and 2005 if he is employed by the Company on the payment date or has been terminated by the Company without cause. Maximum payment amounts under Mr. Klawitter’s retention bonus plan are $119,000 for 2003, $142,800 for 2004 and $166,600 for +2005. The maximum retention bonus payment in each year is reduced by the amount of any payments earned by Mr. Klawitter pursuant to any Company incentive plans during the fiscal year immediately preceding the retention bonus payment date. \ No newline at end of file diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/filing.txt b/raw/filings/0000719733/2005/0001193125-05-188169/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..b4c9d3edc0df708387d4f08cb86f513875261b44 --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/filing.txt @@ -0,0 +1,2810 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended July 2, 2005 +OR +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 0-11559 +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +Washington +91-0849125 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road +Spokane Valley, Washington +99216 +(Address of principal executive offices) +(Zip Code) +Registrant’s +telephone number, including area code: (509) 928-8000 +Securities Registered Pursuant to Section 12(b) of the Act: None +Securities Registered Pursuant to Section 12(g) of the Act: Common stock, +no par value +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the +preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements during the past 90 days. Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not +contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant +is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨ No x +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +The aggregate market value of the voting stock held by non-affiliates of the Registrant was $23,711,973 as of January 1, 2005. +The number of shares of Common Stock of the Registrant outstanding as of September 5, 2005 was 9,693,913 shares. +The Exhibit Index is located at pages 39 - 40. +Documents Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 23, 2005 +Part III +Table of Contents +KEY TRONIC CORPORATION +2005 FORM 10-K +TABLE OF CONTENTS +Page +Part I +Item 1. +Business +3 - 5 +Item 2. +Properties +6 +Item 3. +Legal Proceedings +6 - 7 +Item 4. +Submission of Matters to a Vote of Security Holders +7 +Part II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +8 +Item 6. +Selected Financial Data +8 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +9 - 17 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +17 - 18 +Item 8. +Financial Statements and Supplementary Data +19 - 34 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +35 +Item 9A. +Controls and Procedures +35 +Item 9B. +Other Information +35 +Part III +Item 10. +Directors and Executive Officers of the Registrant +36 - 37 +Item 11. +Executive Compensation +37 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +37 - 38 +Item 13. +Certain Relationships and Related Transactions +38 +Item 14. +Principal Accounting Fees and Services +38 +Part IV +Item 15. +Exhibits and Financial Statement Schedules +39 - 41 +Signatures +42 - 43 +2 +Table of Contents +FORWARD-LOOKING STATEMENTS +This Annual Report contains forward-looking statements in addition to historical information. Forward-looking statements are subject to +certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in +“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, +which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to revise or publicly release the results of any revision to forward-looking statements. Readers should carefully review the risk factors +described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q. +PART I +Item 1. BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, +and its subsidiaries (hereinafter collectively called the “Company”, “Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related +products manufacturing for original equipment manufacturers (OEMs). The Company also manufactures keyboards and other input devices for personal computers, terminals, and workstations primarily in standard layouts that can be sold directly from +inventory on hand. +Key Tronic is now known as an independent provider of +product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing market conditions and the Company’s strengths and capabilities, the Company +shifted its focus to EMS. The EMS industry is comprised of companies that provide a range of manufacturing services for OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to outsourcing manufacturing, +and this trend is expected to continue in the future. +Operations are currently +conducted in facilities in the United States, Mexico and China. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs +and reduced product fulfillment time. +Marketing +The Company provides manufacturing services for outsourced OEM products. Key Tronic provides +a mix of EMS services including: product design, surface mount technologies (SMT) for printed circuit board assembly, tool making, precision plastic molding, liquid injection molding, prototype design, full product builds, and printing screened +silver flexible circuit membranes. +The percentage of revenues from EMS +services for the fiscal years ended July 2, 2005, July 3, 2004, and June 28, 2003 were 95.0%, 91.0% and 87.0%, respectively. Sales of such products have historically not been seasonal in nature, but may be seasonal in the future, if there are +changes in the types of products manufactured. +Although keyboard manufacturing +is still included in the Company’s product offerings, annual keyboard sales continue to decline. During the fiscal years ended July 2, 2005, July 3, 2004, and June 28, 2003, the Company realized revenues of approximately $10.1 million, $13.4 +million and $17.0 million, respectively, from the sale of keyboards representing approximately 5.0%, 9.0% and 13.0% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the +demand for standard products, the Company maintains a purchase-from-stock program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original +system-supplied keyboards. +The Company markets its products and services +primarily through its direct sales department aided by strategically located field sales people and distributors. Although the Company establishes relationships with several independent sales organizations to assist in marketing the Company’s +EMS product lines in the U.S., commissions earned and paid are insignificant. +3 +Table of Contents +The following customers accounted for 10% or more of consolidated revenues in the three fiscal years presented below: +Fiscal Year +2005 +2004 +2003 +Lexmark International, Inc. +19 +% +14 +% +8 +% +Zebra Technologies Corporation +19 +% +12 +% +8 +% +International Game Technology, Inc. +14 +% +4 +% +0 +% +Transaction Printer Group, Inc. +9 +% +10 +% +9 +% +The Clorox Company +8 +% +16 +% +31 +% +For the fiscal years ended July 2, +2005, July 3, 2004, and June 28, 2003, the five largest customers in each year accounted for 68%, 58% and 64% of total sales, respectively. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding a capital equipment base to achieve selective vertical integration and efficiencies in its manufacturing processes. The Company +has invested significant capital into surface mount technologies (SMT) for high volume manufacturing of complex printed circuit board assemblies. The Company designs and develops tooling for injection molding and manufactures the majority of plastic +parts used in the products it manufactures. Additionally, the Company has equipment to produce printed flexible circuit membranes. +Key Tronic uses a variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated +processes include component insertion, SMT, flexible robotic assembly, computerized vision system quality inspection, automated switch and keytop installation, and automated functional testing. +The Company’s automated manufacturing processes enable it to work closely with its +customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the +tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround time during product development. +The Company purchases materials and components for its products from many different suppliers both domestic and international. Key Tronic +develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Backlog +At July 30, 2005, the Company had an order backlog of approximately $63.4 million. This compares with a backlog of approximately $68.1 million at August 1, 2004. Order backlog is not necessarily indicative of future +sales but can be indicative of trends in expected future sales revenue. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change +due to design modifications, customer forecast changes, or other customer requirements. +Research, Development, and Engineering +Research, development, +and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation and allocated information technology and facilities costs. The Company’s RD&E expenses +were $2.9 million, $2.6 million and $2.9 million in fiscal years 2005, 2004, and 2003, respectively. In each of these years, the Company focused most of its RD&E efforts on current customer EMS programs. The lower cost in fiscal year 2004 +compared to fiscal years 2005 and 2003 is due primarily to a 10% pay reduction during part of fiscal year 2004. +Competition +The market for the products and services the Company provides is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically +diverse. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and price. +Trademarks and Patents +The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS +Co.” to better identify its primary business concentration. The Company also owns several keyboard patents; however, since the Company’s focus is EMS, management believes that these patents will not have a significant impact on future +revenues. +4 +Table of Contents +Employees +As of July 2, 2005, the Company had 2,849 employees compared to 2,847 on July 3, 2004 and 2,687 on June 28, 2003. Since the Company can have significant fluctuations in +product demand, it seeks to maintain flexibility in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition to full-time employees. The Company’s employees in Reynosa, Mexico, are +represented by a local union. The Company has no history of any material interruption of production due to labor disputes. +The Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The Company’s employee benefits include +bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year before-tax income targets. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% of an +employee’s salary, and also provides group health, life, and disability insurance plans. The Company also maintains stock option plans and other long term incentive plans for certain employees and outside directors. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in footnote 9 of +the consolidated financial statements of this Annual Report on Form 10-K, under the caption “Enterprise-Wide Disclosures”, and that information is incorporated herein by reference. +5 +Table of Contents +Item 2. PROPERTIES +The Company has manufacturing +and sales operations located in the United States, Mexico and China. The table below lists the locations and square footage of the Company’s operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane, Washington (1) +49,000 +Leased +Sales, research and administration +Spokane, Washington +96,000 +Leased +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +225,000 +Juarez, Mexico (2) +174,000 +Owned +Manufacturing +Juarez, Mexico +49,000 +Leased +Manufacturing and warehouse +Juarez, Mexico (3) +66,000 +Owned +Manufacturing and warehouse +Reynosa, Mexico +140,000 +Leased +Manufacturing +Reynosa, Mexico (4) +48,000 +Leased +Warehouse +Total Mexico +477,000 +Shanghai, China (5) +63,000 +Leased +Manufacturing +Total China +63,000 +Grand Total +765,000 +(1) +On December 27, 2000, the Company sold two contiguous parcels of land and its corporate headquarters building in Spokane to Royal Hills Associates L.L.C. (RHA) for +approximately $6 million in cash. In connection with the sale, the Company entered into a 10-year lease agreement with RHA for one floor of the two-story building, which the Company continues to occupy as its headquarters (see Note 3 to Consolidated +Financial Statements). The Company’s monthly rent payment is $30,875 plus allocated expenses. +(2) +The Company added 9,000 square feet to its main manufacturing facility in Juarez, Mexico +during fiscal year 2004 to accommodate a new 3,000 ton press molding machine and improve product flow of outbound shipping. +(3) +In May 2005, the Company purchased a 66,000 square foot manufacturing facility in Juarez, +Mexico to replace a previously leased facility and to accommodate the shift of the Las Cruces operations into Juarez. +(4) +In July 2003, the Company leased an additional 48,000 square foot warehouse in Reynosa, +Mexico for storage capacity. +(5) +The Company began an assembly operation in Shanghai, China in fiscal year 1999. During fiscal +year 2003, the leased space was increased from 36,000 sq. ft. to 63,000 sq. ft. to accommodate a new surface mount technology (SMT) line for automated circuit board production. +The geographic diversity of these locations allows the Company to offer services near its +customers and its major electronics markets, while reducing labor costs. The Company considers the productive capacity of its current facilities sufficient to carry on the Company’s current business. +The Company shifted its flexible circuit printing in June 2005 to Juarez, Mexico from its +facility in Las Cruces, New Mexico. The Las Cruces facility is no longer being used for operations and is listed for sale. The Company also closed its keyboard sales office in Ireland in July 2005. +Item 3. LEGAL PROCEEDINGS +On December 20, 2001, a +jury in Seattle federal court rendered a verdict in the case of F&G Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic Corporation, United States District Court for the Western +District of Washington, Case No. C99-995C (the “litigation”) finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury awarded damages to the Plaintiffs in the amount of $16.5 +million. The judgment against the Company was subsequently increased to approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a settlement of the litigation with the Plaintiffs (hereafter +called “F&G”). Under the terms of the settlement, the Company has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G of $2.5 million, as well as make quarterly payments to +F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is greater, until the total payment of $7.0 million has been made, provided the total payment was completed by December 15, 2005. On September 1, 2005, the Company made its +final payment to F&G in the amount of $812,000, thereby fulfilling the Company’s obligation of the $7.0 million settlement. +6 +Table of Contents +Reported earnings for the year ended June 28, 2003, include a one-time benefit of $12.2 million ($1.26 per share) for +reversal of the previously recorded F&G litigation accrual. +The Company is +party to certain other lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash +flow. +Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None +7 +Table of Contents +PART II +Item 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Key Tronic Corporation’s common stock is traded on the NASDAQ National Market System under the symbol “KTCC”. Quarterly high and low closing sales prices for Key Tronic common stock for fiscal years +2005 and 2004 were as follows: +2005 +2004 +High +Low +High +Low +First Quarter +$ +3.57 +$ +2.80 +$ +2.65 +$ +2.30 +Second Quarter +3.53 +3.05 +2.49 +1.96 +Third Quarter +3.40 +2.66 +3.00 +2.20 +Fourth Quarter +3.93 +2.23 +4.06 +2.66 +High and low stock prices are based on +the daily closing price reported by the NASDAQ National Market System. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders And Dividends +As of July 2, 2005, the Company had 1,139 shareholders of record. The Company’s current financing agreement contains a covenant that +prohibits the declaration or payment of dividends (see Note 4 to Consolidated Financial Statements). The Company has not paid a cash dividend and does not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation +plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +Item 6: SELECTED FINANCIAL DATA +The following +selected consolidated financial data of the Company should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, +and other information included in this report. +Financial Highlights +(Dollars in thousands, except per share amounts) +Fiscal Years +2005 +2004 +2003 +2002 +2001 +Consolidated Statements of Operations Data: +Net sales +$ +202,877 +$ +148,901 +$ +130,894 +$ +175,591 +$ +165,865 +Gross profit +16,460 +13,237 +14,958 +14,985 +7,556 +Gross margin percentage +8.1 +% +8.9 +% +11.4 +% +8.5 +% +4.6 +% +Operating income (loss) +5,445 +1,789 +2,612 +1,224 +(9,484 +) +Operating margin percentage +2.7 +% +1.2 +% +2.0 +% +0.7 +% +(5.7 +)% +Litigation/settlement recovery (expense) +— +— +12,186 +(20,214 +) +— +Net income (loss) +4,376 +110 +13,409 +(25,362 +) +(11,373 +) +Earnings per share – diluted +0.44 +0.01 +1.39 +(2.62 +) +(1.18 +) +Consolidated Cash Flow Data: +Cash flows provided by (used in) operations +5,114 +(17 +) +(544 +) +919 +7,481 +Capital expenditures +2,918 +1,633 +2,128 +1,142 +720 +Consolidated Balance Sheet Data: +Net working capital (1) +23,006 +23,468 +21,783 +22,261 +22,886 +Total assets +72,901 +67,938 +59,125 +57,439 +74,371 +Long-term liabilities +9,420 +13,452 +13,553 +26,823 +9,389 +Shareholders’ equity +27,639 +23,234 +23,120 +9,711 +35,318 +Book value per share (2) +2.85 +2.40 +2.39 +1.00 +3.65 +Supplemental Data: +Number of shares outstanding at year-end (thousands) +9,694 +9,676 +9,673 +9,673 +9,673 +Number of employees at year-end +2,849 +2,847 +2,687 +1,995 +2,151 +Approximate square footage of operational facilities +765,000 +786,000 +691,000 +664,000 +615,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net +working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of +shares outstanding at the end of the fiscal year. Book value per share measures shareholders’ value as defined by generally accepted accounting principles. +8 +Table of Contents +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +Key Tronic Corporation is an independent provider of electronic manufacturing services (EMS) for original equipment manufacturers (OEMs). The Company’s core strengths include innovative design and engineering +expertise in SMT, electronics, mechanical engineering, precision molding and tooling, combined with high-quality, low-cost production and assembly on a global basis. Our global production capability provides customers with benefits of improved +supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. The Company has made investments in its Mexico and China facilities which give it the production capacity and logistical advantages to +continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and the “Risk and Uncertainties” section. +The EMS industry has historically experienced growth as more OEMs shift to outsourced +manufacturing. Key Tronic sales in fiscal year 2005 increased by 36% over 2004. The end-market demand for the Company’s existing customers’ products drove the significant increase during the year. Current forecasts of existing customer +demand show a possible decrease in revenues for fiscal year 2006. However, the Company has seen an increase in the number of potential new business opportunities with new customers. Actual results will depend on actual levels of customer orders and +the timing of new product wins. The Company believes that it is well positioned in the EMS industry to expand its customer base and continue long-term business growth. +The total number of Key Tronic EMS customers continued to increase during fiscal 2005. Some of these customers have programs that represent +small annual sales while others have multi-million-dollar potential. The concentration of the Company’s largest customers increased during fiscal 2005 as the top five customers sales increased to 68% of total sales in 2005 from 58% in 2004 and +64% in 2003. The Company’s current customer relationships involve a variety of products, including consumer electronics and plastics, household products, gaming devices, specialty printers, educational toys, medical devices, and computer +accessories. +The Company maintains a strong balance sheet with a current ratio +of 1.64 and a long-term debt to equity ratio of 0.32. The Company had cash provided by operations of $5.1 million. In addition, the Company had approximately $12.0 million available from a revolving line of credit based on eligible collateral at +July 2, 2005. The Company maintains a good working relationship with CIT Group/Business Credit, Inc., its asset-based lender, and it believes that internally generated funds and its revolving line of credit should provide adequate capital for +planned growth over the long term. +The EMS industry is intensely competitive, +and Key Tronic, at this time, estimates it has less than 1% of the potential market. The Company believes that it can acquire new business in the future, particularly those programs that require innovative design and engineering, short lead times, +or small initial volumes. The Company is planning for long term growth by utilizing current capacity, improving manufacturing processes, and investing in additional manufacturing equipment. Current challenges facing the Company include the +following: continuing to win new programs, improving operating efficiencies, controlling costs and developing competitive price strategies. +9 +Table of Contents +Results of Operations +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial +information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Years Ended +July 2, 2005 +July 3, 2004 +June 28, 2003 +Net sales +100.0 +% +100.0 +% +100.0 +% +Cost of sales +91.9 +91.1 +88.6 +Gross profit +8.1 +8.9 +11.4 +Operating expenses (income) +Research, development and engineering +1.4 +1.7 +2.2 +Selling +1.1 +1.3 +1.7 +General and administrative +3.4 +4.7 +5.5 +Gain on life insurance proceeds +(0.5 +) +0.0 +0.0 +Operating income +2.7 +1.2 +2.0 +Interest expense +0.6 +0.7 +0.8 +Litigation settlement and other income +0.0 +0.0 +(9.5 +) +Income before income taxes +2.1 +0.5 +10.7 +Income tax provision +0.0 +0.4 +0.5 +Net income +2.2 +% +0.1 +% +10.2 +% +Net Sales +Net sales in fiscal 2005 were $202.9 million compared to $148.9 million and $130.9 million +in fiscal years 2004 and 2003, respectively. +The significant increase in net +sales during 2005 relates directly to increases in the end-market demand of the Company’s primary customer programs and success in winning additional programs from existing and new customers. Sales of keyboards accounted for approximately 5.0% +of revenues compared to 9.0% in 2004. +The increase in net sales during 2004 +compared to 2003 is related to the Company’s successful expansion of the number of manufacturing programs with existing customers and acquisition of new significant customers during the year, offset in part, by a large decrease in demand from a +single EMS customer. Sales of keyboards accounted for approximately 9.0% of revenues in 2004 compared to 13.0% in 2003 as the Company continued to focus its strategy on EMS products. +Cost of Sales +Total cost of sales as a percentage of net sales were 91.9%, 91.1%, and 88.6% for the fiscal years of 2005, 2004, and 2003, respectively. The increase in costs of sales +as a percentage of net sales in each year is due mainly to the competitive nature of the EMS industry to continually reduce prices and changes in product mix, offset in part by increasing manufacturing efficiencies. +Total costs of materials as a percentage of sales were approximately 67.0%, 58.1%, and 57.0% +in fiscal years 2005, 2004, and 2003, respectively. The change from year-to-year is directly related to sales product mix. Products sold in 2005 contained higher dollar materials costs, thereby increasing costs of materials as a percentage of sales. +Direct production costs (direct labor and manufacturing overhead) decreased to +12.9% of total sales in fiscal 2005 from 18.3% in 2004 and 16.0% in 2003. The decrease in 2005 is related to utilization of excess manufacturing capacity (both equipment and indirect support costs). The increase in direct production costs in 2004 +was the result of start-up costs associated with new manufacturing programs. These start-up costs included the costs to increase the Company’s manufacturing and storage space in Juarez, Mexico. The remaining increase in 2004 was due primarily +to adding employees required for more labor-intensive products. +10 +Table of Contents +The Company provides for obsolete and non-saleable inventories based on specific identification of inventory against +current demand and recent usage. The amounts charged to expense were $ 730,000, $162,000, and $203,000 in fiscal years 2005, 2004, and 2003, respectively. Approximately $350,000 of the provision in 2005 was due to the decision to cease supporting +direct European sales of keyboards, with the remaining increase over 2004 relating to domestic keyboards and other computer peripherals that are considered to be obsolete. +The Company provides warranties on certain product sales and estimates warranty costs based on historical experience and anticipated product +returns. The amounts charged to expense increase with total sales and were approximately $345,000, $193,000, and $150,000 in fiscal years 2005, 2004, and 2003, respectively. Most of the increase in fiscal 2005 related to a $100,000 warranty claim on +workmanship of a particular EMS product that has been settled and corrected. The Company does not warrant design defects for EMS customers. +Gross Profit +In fiscal year 2005, gross profit on sales was 8.1% of revenues compared to 8.9% in fiscal year 2004 and 11.4% in fiscal year 2003. The decrease in fiscal year 2005 relates to product mix changes and total materials +costs increases offset in part by improved manufacturing efficiencies. +The +decrease in gross profit from 2004 to 2003 was due primarily to the product mix changes and costs associated with the start-up of new manufacturing programs, offset in part by an insurance settlement in 2004 of $475,000. +Gross profit margins reflect the impact of a number of factors that can vary from period to +period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of the Company’s resources, management of inventories, component pricing and shortages, end +market demand of our customers’ products, fluctuations and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in our operating results. There can be no assurance that gross margins +will not decrease in future periods. +Research, Development and +Engineering +Research, development and engineering expenses (RD&E) +consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. As a percentage of net sales, RD&E has decreased each year from fiscal 2003 +to 2005. The decrease as a percent of sales is due to increasing sales with no significant increases in costs. In each of the fiscal years presented, the Company has focused most of its RD&E efforts on current customers’ EMS programs. +The Company’s total RD&E expenses were $2.9 million, $2.6 million, +and $2.9 million in fiscal years 2005, 2004, and 2003, respectively. The increase in fiscal 2005 is related to the elimination of a 10% pay reduction that occurred during 2004 and incentive plan payments to employees for achieving 2005 profitability +goals. The lower cost in fiscal year 2004 compared to fiscal year 2003 is due primarily to the pay reduction that occurred during 2004. +Selling +Sales and marketing expenses consist principally of salaries and benefits for sales and marketing personnel, advertising and marketing programs, sales commissions, and travel expenses. Similar to RD&E expenses, +selling expenses decreased as a percent of sales relative to the allocated fixed costs in each of the years presented. Approximately half of selling expense relates to fixed salary costs. +The Company’s total selling expenses were $2.2 million, $1.9 million, and $2.3 million in fiscal years 2005, 2004, and 2003, +respectively. The increase in 2005 from 2004 was related to the elimination of a 10% pay reduction, incentive plan bonuses earned, and increased sales commissions. The decrease in 2004 from 2003 was related to a reduction in promotional programs, +commissions, and bonuses earned. +General and Administrative +General and administrative expenses (G&A) consist of employee related costs, travel +expenses and allocated information technology and facilities costs for finance, legal, human resources and executive functions, outside legal and accounting fees, provision for doubtful accounts and business insurance costs. As a percent of sales +G&A was 3.4%, 4.7%, and 4.8% in fiscal years 2005, 2004, and 2003, respectively. +11 +Table of Contents +Total G&A was $7.0 million, $7.0 million and $7.2 million in fiscal years 2005, 2004, and 2003, respectively. In +2005, the Company was able to reduce its business insurance premiums and administrative costs in Ireland directly offsetting the increased bonuses earned and the write-off of bad debt. The decrease in G&A expenses in fiscal year 2004 compared to +fiscal year 2003 was due primarily to a 10% reduction in salaries that was in effect for part of 2004, offset in part by higher business insurance premiums. +Gain on Life Insurance Proceeds +The operating expenses of fiscal 2005 included a gain on life insurance proceeds paid on policies insuring a former executive in the amount of $1.1 million. The Company +does not hold life insurance policies on any other executives or former executives and does not anticipate any gains on life insurance proceeds in the future. +Interest Expense +The Company had net interest expenses of $1.2 million, $1.1 million, and $1.0 million in fiscal years 2005, 2004, and 2003, respectively. Interest expense has remained fairly constant, as the Company has decreased its +average borrowings during the year while interest rates have increased. The Company does not currently use derivatives to hedge interest rate risk. During 2005, the Company began to utilize short-term fixed LIBOR rates on portions of its revolver +for short-term interest savings in anticipation of rate increases. +Other +Income, Net +The Company had net other income of $14,000, $23,000, and +$237,000 in fiscal years 2005, 2004, and 2003, respectively. Other income in fiscal year 2003 is primarily proceeds from the sale of portfolio securities. +Income Tax Provision +The Company had income tax benefit of $(75,000) in fiscal year 2005 compared to an expense of $611,000 in fiscal year 2004 and $600,000 in fiscal year 2003. The tax provisions (benefits) are the result of foreign +taxes on the earnings of foreign subsidiaries. The benefit for fiscal year 2005 relates to the Company’s Mexican subsidiaries revising intercompany agreements upon completing new transfer price studies in the fourth quarter of fiscal 2005, +applying certain Mexican tax credits for the calendar years 2005 and 2004, and a reduction of Mexican statutory rates. The tax expense in 2004 and 2003 relate to tax expense at the former intercompany transfer rates and higher Mexican statutory +rates. +The Company has domestic tax loss carryforwards of approximately $60 +million. In accordance with Financial Accounting Standard No. 109, Accounting for Income Taxes , management assess the sources of future taxable income, which may be available to recognize the deductible differences that comprise deferred tax +assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or all of the deferred tax assets will not be realized. Because the litigation judgment of fiscal year 2002 was considered evidence of the +Company’s possible inability to utilize the balance of the deferred tax assets, the valuation allowance was increased to the net deferred tax asset. Management has determined that a full valuation allowance is still appropriate at this time. +The Company’s tax loss carry-forwards begin expiring in 2006. +International Subsidiaries +The Company offers customers a +complete global manufacturing solution. The Company’s facilities provide its customers the opportunity to have their products manufactured in the facility that best serves specific product manufacturing and distribution needs. Active foreign +subsidiaries are located in the following locations: +• +Key Tronic Juarez SA de CV, owns an SMT, assembly, and molding facility and an assembly facility in Juarez, Mexico and currently leases one other facility for assembly and storage. +This subsidiary is primarily used to support the Company’s U.S. operations. +• +Key Tronic Reynosa SA de CV, leases manufacturing and warehouse facilities in Reynosa, Mexico. This subsidiary is used exclusively to manufacture products for one EMS customer. +• +Key Tronic Computer Peripheral Co., Ltd., leases a facility with SMT and assembly capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide +EMS services for export; however, it is also currently utilized to manufacture electronic keyboards. +Foreign sales from worldwide operations, including domestic exports, were $15.8 million in fiscal year 2005 compared to $14.5 million and $16.2 million in fiscal years +2004 and 2003, respectively. The increase in foreign sales in fiscal 2005 is related to an +12 +Table of Contents +increase in domestic exports to an EMS customer in Europe offset in part by a decrease in foreign sales of keyboards. The Company closed its subsidiary sales +office in Ireland in July 2005 due to decreasing keyboard sales. The decrease in foreign sales for fiscal year 2004 when compared to fiscal year 2003 is a result of declining keyboard sales in Europe. Key Tronic Computer Peripheral Co., Ltd., the +Company’s subsidiary in Shanghai, China, has had only minimal sales to customers in China over the past three fiscal years. +Capital Resources and Liquidity +Cash flows provided by operating activities were $5.1 million in fiscal year 2005 compared to $(17,000) used by operating activities in fiscal year 2004 and $(544,000) in +fiscal year 2003. The cash provided by operations during fiscal year 2005 was due primarily to an increase in net income year-over-year which included non-cash charges for obsolete inventory, warranty, and doubtful accounts totaling $1.2 million. +The increase in operating cash was offset by an increase of $2.6 million in inventory while accounts payable only increased $1.1 million as the Company began taking advantage of early pay discounts. Also contributing to the use of cash was $1.6 +million paid to F&G under the settlement agreement. +Cash used in investing +activities includes capital expenditures and proceeds of life insurance on a former officer. Capital expenditures were $2.9 million, $1.6 million, and $2.1 million in fiscal years 2005, 2004, and 2003, respectively. The Company’s capital +expenditures are primarily for purchases of manufacturing assets to support Company operations in Mexico and China. The Company also uses a variety of operating leases to fund the purchases of operating equipment. During 2005, $1.4 million was +received from life insurance proceeds. +The Company’s primary financing +activity in fiscal years 2005, 2004, and 2003 was borrowing and repayment under the Company’s financing agreement with CIT Group/Business Credit, Inc. (CIT). +The Company’s financing agreement with CIT provides a revolving credit facility of up to $25 million. The revolving loan is secured by +the assets of the Company. The interest rate provisions allow for a variable rate based on either the prime rate or LIBOR rate. The agreement specifies four alternative levels of margin to be added to these base rates depending on compliance with +certain financial covenants. The range of interest being paid to CIT on outstanding balances was 5.87% – 6.75% as of July 2, 2005. The agreement and subsequent amendments contain financial covenants that relate to total equity, earnings before +interest, taxes, depreciation and amortization, and a minimum fixed charge ratio. The revolving loan matures August 22, 2009. As of July 2, 2005, the Company was in compliance with all loan covenants. At July 2, 2005, the outstanding revolving loan +balance was $7.4 million compared to $10.9 million at fiscal year end July 3, 2004. The loan balance decreased as operating cash flow was used for repayments. Based on eligible collateral, approximately $12.0 million was available for drawdown from +the revolving line of credit as of July 2, 2005. +In addition to the +Company’s revolving credit facility payment obligations at July 2, 2005, the Company had a $1.5 million term loan with CIT, $812,000 litigation settlement payment obligation, various lease commitments, and other long term obligations of +$500,000. The Company believes that projected cash from operations, funds available under the revolving credit facility, and leasing capabilities will be sufficient to meet our working and fixed capital requirements through fiscal year 2006 and the +foreseeable future. +Contractual Obligations and Commitments +In the normal course of business, the Company enters into contracts, which obligate the +Company to make payments in the future. +The table below sets forth the +Company’s significant future obligations by fiscal year: +Payments +Due by Fiscal Year (in thousands) +Total +2006 +2007 +2008 +2009 +2010 +Thereafter +Litigation Settlement (1) +$ +812 +812 +CIT Revolving Loan (2) +$ +7,412 +7,412 +CIT Term Loan (3) +$ +1,602 +582 +548 +472 +Capital and Operating Leases (4) +$ +7,410 +3,919 +1,699 +636 +453 +463 +240 +Purchase Orders (5) +(1) +For an in-depth discussion of the litigation settlement, please see the Consolidated +Financial Statements at Note 8, “Commitments and Contingencies”. On September 1, 2005, the Company paid $812,000 and fulfilled its contractual obligation of the settlement. +13 +Table of Contents +(2) +The terms of the CIT revolving loan are discussed in the consolidated financial statements at +Note 4, “Long-Term Obligations”. The Company’s current financing agreement with CIT terminates on August 22, 2009, at which time the unpaid balance of the revolving loan will become immediately payable. However, the Company will more +likely than not extend or replace its revolving loan agreement prior to that date. The amount payable on the Company’s revolving loan changes daily depending upon the amount of cash borrowed to support its operations and the amount of customer +payments received. The amount presented does not include any interest payable. Under the terms of the Company’s agreement with CIT, customers’ payments are applied against the outstanding revolving loan balance as soon as the amounts clear +through the banking system. +Under the terms of +the revolving credit agreement, the Company must meet a number of financial covenants. As of July 2, 2005 the Company was in compliance with all of its loan covenants. Breaching one or more of these covenants could have a material impact on the +Company’s operations or financial condition. +(3) +In May 2005, the Company purchased a manufacturing facility in Juarez, Mexico. The purchase +was funded by a $1.5 million term loan with CIT to be repaid ratably over three years. +(4) +The Company maintains vertically integrated manufacturing operations in Mexico and Shanghai, +China. Such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, SMT lines, and automated insertion and test equipment for the various products the Company is capable of +producing. +In addition, the Company leases some +of its administrative and manufacturing facilities. A complete discussion of properties can be found in Part 1, Item 2 at “Properties”. Leases have proven to be an acceptable method for the Company to acquire new or replacement equipment +and to maintain facilities with a minimum impact on its operating cash flows. +(5) +As of July 2, 2005, the Company had open purchase order commitments for materials and other supplies of approximately $58.5 million. Of the $58.5 million in open +purchase orders, there are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with the Company’s manufacturing levels. In addition, the Company has contracts with its customers that +minimize its exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with the +Company’s suppliers. These agreements depend in part on the type of product purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented in tabular format, the Company also owes its suppliers approximately $25.5 million for +accounts payable and shipments in transit at the end of the fiscal year. The Company generally pays its suppliers in a range from 30 to 120 days depending on terms offered. Quarterly payments to suppliers normally average between $30 and $35 +million. These payments are financed by operating cash flows and the Company’s revolving line of credit. +The Company believes that internally generated cash flows and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months. +Critical Accounting Policies +Revenue Recognition : The Company recognizes revenue when products are shipped. Staff +Accounting Bulletin 104 states that revenue generally is realized or realizable and earned when all of the following criteria are met: +• +Persuasive evidence of an arrangement exists. +• +Delivery has occurred or services have been rendered. +• +The seller’s price to the buyer is fixed or determinable. +• +Collectibility is reasonably assured. +The Company believes that it meets the above criteria for the following reasons: +• +Customer purchase orders confirming the price and shipping terms are required prior to shipment. +• +The terms of the Company’s sales are generally FOB shipping point, meaning that the customer takes ownership of the goods and assumes the risk of loss when the goods leave the +Company’s premises. +• +The seller’s price to the buyer is fixed or determinable – as noted, we require a customer purchase order, which confirms the price and shipping terms. +• +Collectibility is reasonably assured – the credit terms for customers are pre-established so that collection of the account can be reasonably assured. +Inactive, Obsolete and Surplus Inventory Reserve : The Company reserves for +inventories that it deems inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that the Company produces. Demand is determined by +14 +Table of Contents +expected sales or customer forecasts. If expected sales do not materialize, then the Company would have inventory in excess of its reserves and would have to +charge the excess against future earnings. In the case where the Company has purchased material based upon a customer’s forecast, the Company is usually covered by lead-time assurance agreements with each customer. These contracts state that +the financial liability for material purchased within lead-time and based upon the customer’s forecasts, lies with the customer. If the Company purchases material outside the lead-time assurance agreement and the customer’s forecasts do +not materialize, the Company would have the financial liability and would have to charge any excess obsolete inventory against earnings. +Allowance for Doubtful Accounts : The Company values its accounts receivable net of an allowance for doubtful accounts. This allowance is based on estimates of the +portion of accounts receivable that may not be collected in the future, and the amount of this allowance is disclosed in the Company’s consolidated balance sheets. The estimates used are based primarily on specific identification of potentially +uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of the Company’s customers were to develop unexpected and immediate financial +problems that would prevent payment of open invoices, the Company could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty : An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of +this accrual quarterly based on historical analysis and anticipated product returns and rework costs. As the Company has made the transition from manufacturing primarily keyboards to primarily EMS products, its exposure to warranty claims has +declined significantly. The Company’s warranty period for keyboards is generally longer than that for EMS products. Also the Company does not warrant design defects for EMS customers. +Goodwill +In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 142, +“Goodwill and Other Intangible Assets.” SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. Under the statement, the Company records intangible assets that are acquired individually +or with a group of other assets in the financial statements at acquisition. Goodwill is tested for impairment annually. The Company adopted SFAS No. 142 on June 30, 2002, and completed its impairment test during the second quarters of each of the +subsequent fiscal years. The tests did not indicate an impairment of the Company’s stated goodwill of $765,000. +New Accounting Pronouncements +In November 2004, the FASB issued SFAS No. 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4”. The statement amends ARB No. 43, Chapter 4, to clarify +that abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage) should be recognized as current period charges. In addition, it requires that allocation of fixed production overhead to the cost of conversion +be based on the normal capacity of the production facilities. SFAS 151 is effective for inventory costs incurred in the Company’s fiscal year 2006 and thereafter. The Company does not anticipate that the provisions of SFAS 151 will have a +material effect on the consolidated financial statements. +In December 2004, +FASB revised and retitled SFAS No. 123, “Accounting for Stock-Based Compensation” as SFAS No. 123R, “Share Based Payment”. This revised statement requires stock options to be recorded using the fair value method, superseding +Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees”, and its related implementation guidance. Under APB Opinion 25, issuing stock options to employees could have resulted in recognition of no +compensation cost. SFAS 123R eliminates this alternative and requires entities to expense the cost of employee services received in exchange for stock options based on the grant date fair value of those awards. The Company currently accounts for its +employee stock options in accordance with APB Opinion No. 25 while disclosing the pro forma effect of the options had they been recorded under the fair value method. As required by the statement, the Company plans to adopt the revised statement in +its fiscal year 2006 beginning on July 3, 2005. As a result, the Company estimates that compensation expense for previously granted options will approximate $50,000 in fiscal year 2006 and $9,000 in fiscal year 2007. Any future grants would result +in additional compensation expense. +In May 2005, the FASB issued SFAS No. 154, +“Accounting Changes and Error Corrections”. SFAS No. 154 is a replacement of APB No. 20 and SFAS No. 3. SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes +retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS No. 154 is effective for accounting changes and corrections of +errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in the first quarter of fiscal 2007. +15 +Table of Contents +In March 2005, the FASB issued FIN 47 as an interpretation of SFAS No. 143, “Accounting for Asset Retirement +Obligations”. This interpretation clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are +conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even through uncertainly exists about the timing and/or method of settlement. +Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This interpretation also clarifies when an entity would have +sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company does not anticipate that the provision of FIN 47 +will have a material effect on the consolidated financial statements. +RISKS +AND UNCERTAINTIES THAT COULD AFFECT FUTURE RESULTS +The following risks +and uncertainties could affect the Company’s actual results and could cause results to differ materially from past results or those contemplated by the Company’s forward-looking statements. When used herein, the words “expects”, +“believes”, “anticipates” and similar expressions are intended to identify forward-looking statements. +Potential Fluctuations in Quarterly Results The Company’s quarterly operating results have varied in the past and may vary in the future due to a variety of +factors, including changes in overall demand for customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by the Company, its customers and its competitors and changes +in pricing policies by the Company, its customers, its suppliers and its competitors. For example, the Company relies on customers’ forecasts to plan its business. If those forecasts are overly optimistic, the Company’s revenues and +profits may fall short of expectations. Conversely, if those forecasts are too conservative, the Company could have an unexpected increase in revenues and profits. The products which the Company manufactures for its customers have relatively short +product lifecycles, therefore the Company’s business, operating results and financial condition are dependent in significant part on the Company’s ability to obtain orders from new customers and new product programs from existing +customers. +Competition The EMS industry is intensely competitive. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect the Company’s business, operating +results and financial condition. The Company’s inability to provide comparable or better manufacturing services at a lower cost than its competitors could cause sales to decline. In addition, competitors can copy the Company’s +non-proprietary designs after the Company has invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Concentration of Major Customers At present, the Company’s customer base is +highly concentrated and could become even more concentrated. The Company’s largest EMS customer accounted for 19% of net sales in fiscal year 2005. This same customer accounted for 14% of sales in 2004 and 8% in 2003. For the fiscal years ended +2005, 2004, and 2003, the five largest customers accounted for 68%, 58% and 64% of total sales, respectively. There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current +levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the +Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +Dependence on Suppliers The Company is dependent on many suppliers, including sole +source suppliers, to provide key components and raw materials used in manufacturing customers’ products. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or +reductions in shipment of products to our customers which could adversely affect the Company’s operating results and damage customer relationships. +Dependence on Key Personnel The Company’s future success depends in large part on the continued service of its key technical, marketing and management +personnel and on its ability to continue to attract and retain qualified employees. The competition for such personnel is intense and there can be no assurance that the Company will be successful in attracting and retaining such personnel. The loss +of key employees could have a material adverse effect on the Company’s business, operating results and financial condition. +Foreign Manufacturing Operations Virtually all products manufactured by the Company are produced at the Company’s facilities located in Mexico and China. +Accordingly, the Company’s operations are subject to a variety of risks unique to international operations including import and export duties and value added taxes, import and export regulation changes, the burden and cost of compliance with +foreign laws and foreign economic and political risk. +16 +Table of Contents +Technological Change and New Product Risk The markets for the Company’s customers’ products is +characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and relatively short product life cycles. The introduction of products embodying new technologies or the emergence of new industry +standards can render existing products obsolete or unmarketable. The Company’s success will depend upon its customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products +that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of the Company’s customers to do so could substantially harm the Company’s +customers’ competitive positions. There can be no assurance that the Company’s customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving +customer requirements. +Compliance with Current and Future Environmental +Regulation The Company is subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail or choose not to comply with any present or +future regulations, we could be subject to future liabilities or the suspension of current manufactured products. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, +substitute materials, or incur other significant expenses to comply with government regulations. +Foreign Currency Fluctuations A significant portion of the Company’s operations and customers are in foreign locations. As a result, transactions may occur in currencies other than the U.S. dollar. +Exchange rate fluctuations among other currencies used by the Company could directly or indirectly affect our financial results. Future currency fluctuations are dependent upon a number of factors and cannot be easily predicted. The Company +currently does not use financial instruments to hedge foreign currency fluctuation and unexpected expenses could occur from future fluctuations in exchange rates. +Dilution and Stock Price Volatility As of July 2, 2005, there were outstanding options for the purchase of approximately 2.0 million +shares of common stock of the Company (Common Stock), of which options for approximately 1.9 million shares were vested and exercisable. Holders of the Common Stock will suffer immediate and substantial dilution to the extent outstanding options to +purchase the Common Stock are exercised. The stock price of the Company may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to the Company such as +variations in quarterly operating results or changes in analysts’ earnings estimates, or to factors relating to the EMS and computer industries or to the securities markets in general, which, in recent years, have experienced significant price +fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company’s major market risk relates to its secured debt. The Company’s debt is secured by substantially +all of the Company’s assets. The interest rates applicable to the Company’s revolving loan fluctuate with the JP Morgan Chase Bank prime rate and LIBOR rates. The Company does not currently enter into derivative transactions or leveraged +swap agreements. +Although the Company has international operations, the +functional currency for all active subsidiaries is the U.S. dollar. The Company imports raw materials that are used in its manufacturing operations. The majority of the Company’s purchases are denominated in U.S. dollars and are paid under +normal trade terms. The Company currently does not hedge the exposure to foreign currency exchange rate fluctuations. +17 +Table of Contents +The table below presents principal (or notional) amounts and related weighted average variable rates by fiscal year of +maturity. The weighted average variable interest rates for fiscal years 2004 through 2006 are estimated based on current rates as of July 2, 2005. These forward rates have been increased by current levels of margins based on the financing agreement +with CIT. The Company’s long term debt could increase or decrease depending upon cash needs over the period of time that the financing agreement remains in place with CIT. The JP Morgan Chase Bank prime rate and LIBOR will fluctuate with the +market and could go up or down depending on market conditions. +Fiscal Years +Fair Value +July 2, 2005 +(In thousands) +2006 +2007 +2008 +2009 +2010 +Total +Long term debt: +Secured revolving debt +$ +7,412 +$ +7,412 +$ +7,412 +Secured term loan +500 +500 +458 +$ +1,458 +$ +1,458 +Average interest rate +6.75 +% +6.75 +% +6.75 +% +6.02 +% +6.14 +% +18 +Table of Contents +Item 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Shareholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying +consolidated balance sheets of Key Tronic Corporation and subsidiaries (the Company) as of July 2, 2005 and July 3, 2004, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in +the period ended July 2, 2005. We have also audited the schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these +financial statements and schedule based on our audits. +We conducted our audits +in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements and schedule are free +of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for +designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An +audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and schedule. An audit also includes assessing the accounting principles used and significant estimates made by management, as +well as evaluating the overall presentation of the financial statements and schedule. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation and +subsidiaries at July 2, 2005 and July 3, 2004, and the results of its operations and its cash flows for each of the three years in the period ended July 2, 2005 in conformity with accounting principles generally accepted in the United States of +America. +Also, in our opinion, the schedule presents fairly, in all material +respects, the information set forth therein. +/s/ BDO Seidman, LLP +Spokane, Washington +August 11, 2005 +19 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 2, 2005 +July 3, 2004 +ASSETS +Current assets: +Cash and cash equivalents +$ +1,463 +$ +600 +Trade receivables, less allowance for doubtful accounts of $158 and $60 +24,191 +24,439 +Inventories +29,712 +27,848 +Other +3,482 +1,833 +Total current assets +58,848 +54,720 +Property, plant and equipment, net +10,011 +11,131 +Other assets: +Restricted cash +1,158 +705 +Real estate +1,693 +— +Other, net of accumulated amortization of $758 and $696 +426 +617 +Goodwill +765 +765 +Total assets +$ +72,901 +$ +67,938 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +25,475 +$ +24,354 +Accrued compensation and vacation +5,241 +4,015 +Current portion of litigation settlement +812 +925 +Current portion of other long-term obligations +735 +606 +Other +3,579 +1,352 +Total current liabilities +35,842 +31,252 +Long-term liabilities: +Revolving loan +7,412 +10,851 +Litigation settlement +— +1,536 +Other long-term obligations +2,008 +1,065 +Total long-term liabilities +9,420 +13,452 +Commitments and contingencies (Notes 4 and 8) +Shareholders’ equity +Common stock, no par value, authorized 25,000 shares; issued and outstanding 9,694 and 9,676 shares, respectively +38,426 +38,397 +Accumulated deficit +(10,787 +) +(15,163 +) +Total shareholders’ equity +27,639 +23,234 +Total liabilities and shareholders’ equity +$ +72,901 +$ +67,938 +See accompanying notes to consolidated +financial statements. +20 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +Years Ended +(In thousands, except per share amounts) +July 2, +2005 +July 3, +2004 +June 28, +2003 +Net sales +$ +202,877 +$ +148,901 +$ +130,894 +Cost of sales +186,417 +135,664 +115,936 +Gross profit on sales +16,460 +13,237 +14,958 +Operating expenses (income): +Research, development and engineering +2,880 +2,583 +2,913 +Selling +2,229 +1,900 +2,250 +General and administrative +6,966 +6,965 +7,183 +Gain on life insurance proceeds +(1,060 +) +— +— +Operating income +5,445 +1,789 +2,612 +Interest expense, net +1,158 +1,091 +1,026 +Litigation settlement +— +— +(12,186 +) +Other income, net +(14 +) +(23 +) +(237 +) +Income before income taxes +4,301 +721 +14,009 +Income tax provision (benefit) +(75 +) +611 +600 +Net income +$ +4,376 +$ +110 +$ +13,409 +Earnings per share: +Earnings per common share – basic +$ +0.45 +$ +0.01 +$ +1.39 +Weighted average shares outstanding – basic +9,684 +9,673 +9,673 +Earnings per common share – diluted +$ +0.44 +$ +0.01 +$ +1.39 +Weighted average shares outstanding – diluted +9,926 +9,793 +9,673 +See accompanying notes to consolidated +financial statements. +21 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY +Common Stock +Accumulated +(In thousands) +Shares +Amount +Deficit +Total +Balances, June 29, 2002 +9,673 +$ +38,393 +$ +(28,682 +) +$ +9,711 +Net income – 2003 +13,409 +13,409 +Balances, June 28, 2003 +9,673 +38,393 +(15,273 +) +23,120 +Net income – 2004 +110 +110 +Exercise of stock options +3 +4 +4 +Balances, July 3, 2004 +9,676 +38,397 +(15,163 +) +23,234 +Net income – 2005 +4,376 +4,376 +Exercise of stock options +18 +29 +29 +Balances, July 2, 2005 +9,694 +$ +38,426 +$ +(10,787 +) +$ +27,639 +See accompanying notes to consolidated +financial statements. +22 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +Years Ended +(In thousands) +July 2, 2005 +July 3, 2004 +June 28, 2003 +Increase (decrease) in cash and cash equivalents: +Cash flows from operating activities: +Net income +$ +4,376 +$ +110 +$ +13,409 +Adjustments to reconcile net income to cash provided (used) by operating activities: +Depreciation and amortization +2,366 +2,957 +3,016 +Accretion of deferred gain on sale of building +(78 +) +(78 +) +(78 +) +Provision for obsolete inventory +730 +162 +203 +Provision for (recovery of) doubtful receivables +140 +— +(56 +) +Provision for warranty +345 +193 +150 +Litigation settlement +— +— +(12,186 +) +Loss on sale of assets +149 +14 +20 +Gain on life insurance proceeds +(1,060 +) +— +— +Changes in operating assets and liabilities: +Trade receivables +108 +(7,361 +) +3,956 +Inventories +(2,594 +) +(3,859 +) +(5,959 +) +Other assets +(1,983 +) +145 +(22 +) +Accounts payable +1,121 +11,209 +(1,264 +) +Accrued compensation and vacation +1,226 +(198 +) +1,410 +Litigation settlement +(1,649 +) +(1,256 +) +(3,576 +) +Other liabilities +1,917 +(2,055 +) +433 +Cash provided (used) by operating activities +5,114 +(17 +) +(544 +) +Cash flows from investing activities: +Purchase of property and equipment +(2,868 +) +(1,633 +) +(2,128 +) +Proceeds from sale of property and equipment +8 +4 +46 +Proceeds from life insurance +1,447 +— +— +Cash used by investing activities +(1,413 +) +(1,629 +) +(2,082 +) +Cash flows from financing activities: +Payment of financing costs +(90 +) +(35 +) +(150 +) +Proceeds from exercise of stock options +29 +4 +— +Proceeds from long-term debt +1,500 +538 +— +Repayment of long-term debt +(385 +) +(641 +) +— +Borrowing under revolving credit agreement +210,152 +146,805 +139,000 +Repayment of revolving credit agreement +(213,591 +) +(145,818 +) +(135,611 +) +Decrease (increase) in restricted cash +(453 +) +437 +(862 +) +Cash provided (used) by financing activities +(2,838 +) +1,290 +2,377 +Increase (decrease) in cash and cash equivalents +863 +(356 +) +(249 +) +Cash and cash equivalents, beginning of year +600 +956 +1,205 +Cash and cash equivalents, end of year +$ +1,463 +$ +600 +$ +956 +Supplemental cash flow information: +Interest payments +$ +1,100 +$ +865 +$ +763 +Income tax payments, net of refunds +$ +247 +$ +1,015 +$ +348 +See accompanying notes to consolidated +financial statements. +23 +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs), and also +manufactures keyboards and other input devices. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly +owned subsidiaries in Ireland, Mexico, and China. Intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported +amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Significant estimates include the allowance +for doubtful receivables, the provision for obsolete and non-saleable inventories, the valuation allowances on deferred tax assets, valuation of goodwill, and the provision for warranty costs. Actual results could differ from those estimates. +Cash Equivalents +The Company considers investments with an original maturity of three months or less to be +cash equivalents. Cash equivalents are carried at cost, which approximates fair value. +The restricted cash balance includes an approximately $500,000 deposit required by the state of Washington for the Company’s estimated maximum workers’ compensation liability for the period in which the Company was self-insured. +The Company no longer self-insures workers’ compensation liabilities but the deposit will be required to be maintained for a number of years into the future. The remaining amounts in restricted cash are amounts in the Company’s bank +account that cannot be used for any other purpose than to pay down the Company’s long term revolving line of credit. +Allowance for Doubtful Accounts +The Company evaluates the collectibility of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management +reasonably estimates will be collected. A specific allowance is recorded against receivables that are considered to be impaired based on the Company’s knowledge of the financial condition of the customer and all attempts to collect fail. In +determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment, and historical experience. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. The Company provides for obsolete and +non-saleable inventories based on specific identification of inventory against current demand and recent usage. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected lives of the assets. Internally constructed molds and dies +are depreciated over the expected useful lives of one to two years. +24 +Table of Contents +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment +whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Deferred Loan Fees +Deferred loan fees included in other assets are amortized using the interest method over the term of the related loan agreement. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy +of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company began to self-fund its +domestic employee health plan on June 30, 2004. The Company contracted a separate administrative service company to supervise and administer the program and act as representative. The Company also insures for claims exceeding $50,000 and if the +aggregate annual claims amount to more than 125% of expected claims for the plan year. We estimate our exposure for claims incurred but not paid at the end of each reporting period and use historical information supplied by our insurance carrier and +broker to estimate our liability for these claims. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Our actual claims experience may differ +from our estimates. +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product +under contractual terms, which are generally FOB shipping point. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. Generally, there are no formal customer acceptance requirements or further +obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of +manufactured product based on management’s analysis of historical returns. +Revenue from engineering design and development services, which are generally performed under contract of short term durations, is recognized as costs are incurred utilizing the percentage-of-completion method. Revenue from engineering +design and development services is less than one percent of total revenue in each of the fiscal years presented. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are +reported in net sales. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed costs +of electronic manufacturing services (EMS) as well as design and engineering costs associated with the production of EMS programs. Such costs are charged to expense as incurred. +Income Taxes +The Company accounts for income taxes in accordance with provisions of Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income +Taxes.” Under the asset and liability method prescribed by SFAS No. 109, deferred income taxes are provided for temporary differences between the financial reporting and tax bases of assets and liabilities. Deferred taxes are measured using +provisions of currently enacted tax laws. Tax credits are accounted for as a reduction of income taxes in the year the credit originates. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that +will be likely realized. The effect of changes in tax rates is recognized in the period in which the rate change occurs. Determination of the unrecognized deferred tax liability on foreign subsidiary undistributed earnings is not practicable. +25 +Table of Contents +Earnings Per Share +Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings +(loss) per share is computed by dividing net income (loss) by the weighted average number of common and common equivalent shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of +stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that +would have an antidilutive effect on earnings per share. +Foreign Currency +Transactions +The functional currency of the Company’s subsidiaries +in Ireland, Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses are included in general and administrative expenses. +Fair Value of Financial Instruments +The carrying values of financial instruments reflected on the balance sheets at July 2, 2005 and July 3, 2004, reasonably approximate their fair value. Based on the +borrowing rates currently available to the Company for loans with similar terms and average maturities, the fair value of long-term debt is estimated to be $8.9 million and $10.9 million, respectively, as of July 2, 2005 and July 3, 2004, which +approximates the carrying values. +Stock-based Compensation +The Company adopted the pro-forma disclosure only requirements of SFAS No. 123 +“Accounting for Stock Based Compensation”, and accordingly accounts for its stock-based awards to employees using the intrinsic value method in accordance with APB No. 25 “Accounting for Stock Issued to Employees”. Under APB 25, +compensation expense is recognized only if the option price is less than the quoted market price of the Company’s stock at the date of the option grant. Under SFAS No. 123, the fair value of stock-based awards to employees is calculated through +the use of option pricing models. These models require subjective assumptions, including future stock price volatility and expected time to exercise. The Company’s calculations were made using the Black-Scholes option pricing model with the +following weighted average assumptions: expected life, 60 months; stock volatility, 104.12% in 2005, 111.74% in 2004, and 107.96% in 2003; risk free interest rates, 3.37% in 2005 and 3.11% in 2004 and 2003, and no dividends during the expected term. +The weighted average fair values of options granted during fiscal years 2005, 2004, and 2003 were $2.58, $2.20, and $1.16 per share, respectively. +For purposes of disclosure under SFAS No. 123, the following is the pro forma effect of the options had they been recorded under the fair value method (no tax effect has +been included because of offsetting tax valuations): +Years Ended +July 2, 2005 +July 3, 2004 +June 28, 2003 +(in thousands, except per share information) +Net income as reported +$ +4,376 +$ +110 +$ +13,409 +Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards +(93 +) +(130 +) +(387 +) +Pro forma net income (loss) +$ +4,283 +$ +(20 +) +$ +13,022 +Earnings (loss) per share: +Basic – as reported +$ +0.45 +$ +0.01 +$ +1.39 +Diluted – as reported +$ +0.44 +$ +0.01 +$ +1.39 +Basic – pro forma +$ +0.44 +$ +(0.00 +) +$ +1.35 +Diluted – pro forma +$ +0.43 +$ +(0.00 +) +$ +1.35 +26 +Table of Contents +Goodwill +In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 changed the accounting +for goodwill from an amortization method to an impairment-only approach. Under the statement, the Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. Goodwill +is tested for impairment annually. The Company adopted SFAS No. 142 on June 30, 2002, and completed its impairment test during the second quarter of each fiscal year. The tests did not indicate an impairment of the Company’s stated goodwill of +$765,000. +New Accounting Pronouncements +In November 2004, the FASB issued SFAS No. 151, “Inventory Costs an amendment of ARB +No. 43, Chapter 4”. The statement amends ARB No. 43, Chapter 4, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage) should be recognized as current period charges. In addition, it +requires that allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for inventory costs incurred in the Company’s fiscal year 2006 and thereafter. +The Company does not anticipate that the provisions of SFAS 151 will have a material effect on the consolidated financial statements. +In December 2004, the Financial Accounting Standards Board (FASB) revised and retitled Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for +Stock-Based Compensation” as SFAS No. 123R, “Share Based Payment”. This revised statement requires stock options to be recorded using the fair value method, superseding Accounting Principles Board (APB) Opinion No. 25, +“Accounting for Stock Issued to Employees”, and its related implementation guidance. Under APB Opinion 25, issuing stock options to employees could have resulted in recognition of no compensation cost. SFAS 123R eliminates this alternative +and requires entities to expense the cost of employee services received in exchange for stock options based on the grant date fair value of those awards. The Company currently accounts for its employee stock options in accordance with APB Opinion +No. 25 while disclosing the pro forma effect of the options had they been recorded under the fair value method. As required by the statement, the Company plans to adopt the revised statement in its fiscal year 2006 beginning on July 3, 2005. As a +result, the Company estimates that compensation expense for previously granted options will approximate $50,000 in fiscal year 2006 and $9,000 in fiscal year 2007. +In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”. SFAS No. 154 is a replacement of APB No. 20 +and SFAS No. 3. SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change +in accounting principle and the reporting of a correction of an error. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in +the first quarter of fiscal 2007. +In March 2005, the FASB issued FIN 47 as an +interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations”. This interpretation clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset +retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even through +uncertainly exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably +estimated. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December +15, 2005. The Company does not anticipate that the provision of FIN 47 will have a material effect on the consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2005, 2004, and 2003 ended on July 2, 2005, July 3, 2004, and June 28, 2003, respectively. +Fiscal year 2006 will end on July 1, 2006. Fiscal 2005 and 2003 were 52 week years and fiscal 2004 was a 53 week year. +27 +Table of Contents +2. INVENTORIES +Components of inventories were as follows: +July 2, 2005 +July 3, 2004 +(in thousands) +Finished goods +$ +10,932 +$ +10,984 +Work-in-process +3,414 +2,926 +Raw materials +18,531 +17,119 +Reserve for obsolescence +(3,165 +) +(3,181 +) +$ +29,712 +$ +27,848 +3. PROPERTY, PLANT AND EQUIPMENT +Life +July 2, 2005 +July 3, 2004 +(in years) +(in thousands) +Land +— +$ +970 +$ +1,730 +Buildings and improvements +3 to 30 +10,179 +11,724 +Equipment +1 to 10 +50,940 +50,187 +Furniture and fixtures +3 to 5 +6,259 +6,412 +68,348 +70,053 +Accumulated depreciation +(58,337 +) +(58,922 +) +$ +10,011 +$ +11,131 +In July 2005, the Company completed +its transition of operations in Las Cruces, New Mexico to its Juarez, Mexico facility. The Las Cruces real estate is now listed for sale and the associated net book value of $1.7 million is separately classified. +In December 2000, the Company sold its headquarters building, located in Spokane, Washington. +In conjunction with the sale, the Company entered into a ten year lease agreement for a portion of the building. The gain on the sale of the building was deferred under other long-term obligations and is amortized to other income over the remaining +lease term. +4. LONG-TERM DEBT +The Company has entered into a financing agreement with CIT Group/Business Credit, Inc. +(CIT) which provides a revolving credit facility up to $25 million. The revolving loan is secured by the assets of the Company. The interest rate provisions allow for a variable rate based on either the prime rate or LIBOR rate. The agreement +specifies four alternative levels of margin to be added to these base rates depending on compliance with certain financial covenants. The range of interest being paid to CIT on outstanding balances was 5.87%– 6.75% as of July 2, 2005. The +agreement and subsequent amendments contain financial covenants that relate to total equity, earnings before interest, taxes, depreciation and amortization, and a minimum fixed charge ratio. The revolving loan matures August 22, 2009. As of July 2, +2005, the Company was in compliance with all loan covenants. At July 2, 2005, the outstanding revolving loan balance was $7.4 million compared to $10.9 million at fiscal year end July 3, 2004. Based on eligible collateral, approximately $12.0 +million was available to draw from the revolving line of credit as of July 2, 2005. +In addition to the Company’s revolving credit facility payment obligations, the Company has a $1.5 million term loan with CIT which is included in other long term liabilities. The loan requires ratable payments over 3 years with a +variable rate of 6.75% at July 2, 2005. The term loan was used to purchase the new Juarez, Mexico manufacturing facility in May 2005 and is collateralized by the real estate in Las Cruces, New Mexico. +28 +Table of Contents +5. INCOME TAXES +Income tax expense (benefit) consists of the following: +Year Ended +July 2, +2005 +July 3, +2004 +June 28, +2003 +(in thousands) +Current income tax expense (benefit): +Federal +$ +— +$ +— +$ +(37 +) +Foreign +(75 +) +611 +637 +State +— +— +— +(75 +) +611 +600 +Deferred income tax expense (benefit): +Federal +810 +(464 +) +4,264 +Foreign +— +— +— +State +90 +(16 +) +272 +900 +(480 +) +4,536 +Change in valuation allowance +(900 +) +480 +(4,536 +) +Total income tax expense (benefit) +$ +(75 +) +$ +611 +$ +600 +The Company had an income tax benefit +of $75,000 in fiscal year 2005 compared to an expense of $611,000 in fiscal year 2004 and $600,000 in fiscal year 2003. The tax provisions (benefits) are the result of foreign taxes on the earnings of foreign subsidiaries. The benefit for fiscal +year 2005 relates to the Company’s Mexican subsidiaries revising prior intercompany billings upon completing new transfer price studies in the fourth quarter of fiscal 2005, applying certain Mexican tax credits for the calendar years 2005 and +2004, and a reduction of Mexican statutory rates. The tax expense in 2004 and 2003 relate to tax expense at higher intercompany transfer rates and higher Mexican statutory rates. +The Company’s effective tax rate differs from the federal tax rate as follows: +Year Ended +July 2, 2005 +July 3, 2004 +June 28, 2003 +(in thousands) +Federal income tax expense (benefit) at statutory rates +$ +1,462 +$ +245 +$ +4,763 +Effect of foreign taxes +(574 +) +110 +(101 +) +State tax (net of federal effect) +43 +7 +140 +Life insurance +(274 +) +65 +65 +Other +168 +(296 +) +269 +Change in valuation allowance +(900 +) +480 +(4,536 +) +Income tax provision (benefit) +$ +(75 +) +$ +611 +$ +600 +The domestic and foreign components of +income (loss) before income taxes were: +Year Ended +July 2, 2005 +July 3, 2004 +June 28, 2003 +(in thousands) +Domestic +$ +2,874 +$ +(709 +) +$ +11,900 +Foreign +1,427 +1,430 +2,109 +Income (loss) before income taxes +$ +4,301 +$ +721 +$ +14,009 +29 +Table of Contents +Deferred income taxes result from temporary differences in the timing of recognition of revenue and expenses. Deferred +income tax assets and liabilities consist of the following at: +July 2, 2005 +July 3, 2004 +(in thousands) +Inventory +$ +1,467 +$ +1,675 +Vacation accrual +341 +342 +Litigation settlement (current portion) +276 +315 +Other +316 +168 +Current deferred income tax assets +2,400 +2,500 +Current portion of valuation allowance +(2,400 +) +(2,500 +) +Current deferred income tax assets, net of valuation allowance +$ +— +$ +— +Depreciation and amortization +$ +(261 +) +$ +22 +State deferred taxes +597 +615 +Litigation settlement (non-current portion) +— +522 +Net operating loss carryforwards +20,317 +19,971 +Tax credit carryforwards +388 +536 +Other +259 +434 +Noncurrent deferred income tax assets +21,300 +22,100 +Valuation allowance, net of current portion +(21,300 +) +(22,100 +) +Noncurrent deferred income tax assets, net of valuation allowance +$ +— +$ +— +Total deferred income tax assets +$ +— +$ +— +SFAS No. 109 requires that management +assess the sources of future taxable income, which may be available to recognize the deductible differences that comprise deferred tax assets. A valuation allowance against deferred tax assets is required if it is more likely than not that some or +all of the deferred tax assets will not be realized. Management has determined that a valuation allowance equal to the net deferred tax assets is appropriate. +At July 2, 2005, the Company had net operating loss carryforwards approximating $60 million. The net operating loss carryforwards expire in varying amounts from fiscal +years ending in 2006 through 2025. The Company also has general business credits and alternative minimum tax credits approximating $169,000 and $220,000, respectively. The general business credits expire in varying amounts from fiscal years ending +in years 2006 through 2009 and the alternative minimum tax credits do not expire. Utilization of net operating loss carryforwards would be limited in the event the Company’s ownership changes more than 50% in a three-year period. +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (loss) (the numerator) by the weighted-average number of common shares +outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents. The following table presents a reconciliation of the denominator +and the number of antidilutive common share options that were not included. These antidilutive securities occur when options outstanding have an option price greater than the average market price for the period. +Fiscal Years Ending +2005 +2004 +2003 +Total weighted average shares – basic +9,684,399 +9,673,128 +9,672,580 +Effect of dilutive common stock options +241,355 +119,707 +— +Total weighted average shares – diluted +9,925,754 +9,792,835 +9,672,580 +Antidilutive options not included in diluted earnings per share +930,150 +1,759,391 +2,086,086 +30 +Table of Contents +7. STOCK OPTION AND BENEFIT PLANS +The Company has executive stock option plans for certain key employees. Options under these plans vest over one to five years and become +exercisable as they vest. Options under the plans become exercisable in full immediately prior to the occurrence of a “Change in Control” as defined in the plan documents. The Company has reserved 2,795,000 shares for issuance under these +plans. As of July 2, 2005, 1,716,000 options were outstanding of which 1,676,829 shares were exercisable. There are 149,667 shares available for future grant under these option plans. These options expire ten years from the date of grant. +The Company also has a stock option plan for “Nonemployee +Directors.” Options under this plan vest over a three-year period and are exercisable as they vest. The Company has reserved 300,000 shares for issuance under this plan. As of July 2, 2005, 269,650 options were outstanding of which 226,250 +shares were exercisable. There are no shares available for future grant under this plan. These options expire ten years from the date of grant. +Compensation expense for options will be recorded if the exercise price of the option is less than the closing market price of the stock on the date of grant. There was +no compensation expense incurred in conjunction with options issued in fiscal years 2005, 2004, or 2003, as all options were granted at exercise prices equal to fair market value. See Note 1 for the pro forma effect if the Company had accounted for +the stock options using fair value methods. +Following is a +summary of plan activity: +Price Range +Number +Of Options +Weighted Average +Exercise Price +Outstanding, June 29, 2002 +$1.54 to $16.25 +2,081,304 +$ +4.81 +Granted during 2003 +$1.15 to $ 1.20 +160,000 +$ +1.16 +Expired or canceled +$1.15 to $16.25 +(155,218 +) +$ +6.04 +Outstanding, June 28, 2003 +$2.75 to $16.25 +2,086,086 +$ +4.44 +Granted during 2004 +$ 2.20 +37,500 +$ +2.20 +Exercised +$ 1.15 +(3,333 +) +$ +1.15 +Expired or canceled +$1.15 to $ 9.50 +(48,362 +) +$ +7.62 +Outstanding, July 3, 2004 +$1.15 to $16.25 +2,071,891 +$ +4.33 +Granted during 2005 +$2.96 to $ 3.40 +29,650 +$ +3.33 +Exercised +$1.15 to $ 2.81 +(18,000 +) +$ +1.61 +Expired or canceled +$1.15 to $ 9.50 +(97,891 +) +$ +6.78 +Outstanding July 2, 2005 +$1.15 to $16.25 +1,985,650 +$ +4.22 +Additional information regarding +options outstanding as of July 2, 2005, is as follows: +Options +Outstanding +Options +Exercisable +Range of +Exercise Prices +Number +Outstanding +Weighted Avg. +Remaining +Contractual +Life (yrs.) +Weighted +Avg. Exercise +Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$ 1.15 - $ 1.73 +132,000 +5.2 +$ +1.18 +97,829 +$ +1.19 +$ 1.74 - $ 2.60 +167,500 +5.1 +$ +2.10 +148,750 +$ +2.09 +$ 2.61 - $ 3.92 +785,650 +5.5 +$ +2.81 +756,000 +$ +2.79 +$ 3.93 - $ 5.89 +684,500 +3.9 +$ +5.07 +684,500 +$ +5.07 +$ 5.90 - $ 8.85 +151,000 +3.7 +$ +7.54 +151,000 +$ +7.54 +$13.31 - $16.25 +65,000 +1.6 +$ +16.25 +65,000 +$ +16.25 +$ 1.15 - $16.25 +1,985,650 +4.6 +$ +4.22 +1,903,079 +$ +4.31 +The Company also has a defined +contribution plan available to U.S. employees who have attained age 21. The Company contributes an amount equal to 100% of the employee’s contribution on the first 3% of the employee’s compensation and an additional 50% of the +employee’s contribution on the following 2% of the employee’s compensation. Company contributions to the plan were $380,153, $370,336, and $366,190 in fiscal years 2005, 2004 and 2003, respectively. +31 +Table of Contents +8. COMMITMENTS AND CONTINGENCIES +Leases: The Company has operating leases for certain equipment and production facilities, which expire at various dates during the +next seven years. Future minimum payments under non-cancelable operating and capital leases with initial or remaining terms of one year or more at July 2, 2005, are summarized as follows (in thousands): +Fiscal Years Ending +Operating +Leases +Capital +Leases +2006 +$ +3,864 +$ +55 +2007 +1,693 +6 +2008 +630 +6 +2009 +448 +5 +2010 +463 +— +Thereafter +240 +— +Total minimum lease payments +$ +7,338 +72 +Amount representing interest +(4 +) +Present value of lease payments +68 +Current portion +(52 +) +Capital lease obligations, net of current portion +$ +16 +As of July 2, 2005, the gross carrying +amount of the Company’s equipment financed under capital leases amounted to approximately $538,000. Accumulated depreciation for property and equipment under capital leases totaled approximately $286,000. The weighted average interest rate on +these capital leases is approximately 8.50% and expire at various dates through fiscal year 2009. +Rental expenses under operating leases were approximately $4.5 million, $5.0 million, and $4.6 million in 2005, 2004, and 2003, respectively. +Warranty Costs: The Company provides warranties on certain product sales and allowances for estimated warranty costs are recorded +during the period of sale. The determination of such allowances requires us to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company currently establishes warranty reserves based +on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. +If actual return rates and/or repair and replacement costs differ significantly from our estimates, adjustments to recognize additional cost of sales may be required in +future periods. +Components of the reserve for warranty costs during 2005, +2004, and 2003 were as follows: +Balance at June 29, 2002 +$ +294,270 +Additions related to current period sales +150,000 +Warranty costs incurred in the current period +(283,126 +) +Balance at June 28, 2003 +161,144 +Additions related to current period sales +192,715 +Warranty costs incurred in the current period +(180,127 +) +Balance at July 3, 2004 +173,732 +Additions related to current period sales +345,226 +Warranty costs incurred in the current period +(273,103 +) +Balance at July 2, 2005 +$ +245,855 +32 +Table of Contents +Litigation : On December 20, 2001, a jury in Seattle federal court rendered a verdict in the case of F&G +Scrolling Mouse, LLC, Fernando Falcon and Federico Gilligan v. Microsoft Corporation, Honeywell, Inc., and Key Tronic Corporation, United States District Court for the Western District of Washington, Case No. C99-995C (the “litigation”) +finding that Key Tronic misappropriated trade secrets and breached a confidentiality agreement with Plaintiffs. The jury awarded damages to the Plaintiffs in the amount of $16.5 million. The judgment against the Company was subsequently increased to +approximately $19.2 million through an award of pre-judgment interest. On October 24, 2002, the Company reached a settlement of the litigation with the Plaintiffs (hereafter called “F&G”). Under the terms of the settlement, the Company +has agreed to pay F&G a total of $7.0 million. The Company was required to make an initial payment to F&G of $2.5 million, as well as make quarterly payments to F&G of $200,000 or 50% of Key Tronic’s operating income, whichever is +greater, until the total payment of $7.0 million has been made, provided the total payment was completed by December 15, 2005. On September 1, 2005, the Company made its last payment to F&G in the amount of $812,000, thereby fulfilling the +Company’s obligation of the $7.0 million settlement. +Reported earnings +for the year ended June 28, 2003, include a one-time benefit of $12.2 million ($1.26 per share) for reversal of the previously recorded F&G litigation accrual. +The Company is party to certain other lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, +individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +9. ENTERPRISE-WIDE DISCLOSURES +Management organizes its business around EMS and keyboards based on geographic area. These businesses have been aggregated into one segment as each has similar economic +characteristics, and the nature of the business, its production processes, customers and distribution methods are similar. +Of the revenues for the years ended July 2, 2005, July 3, 2004, and June 28, 2003, EMS sales were $192.8 million, $135.5 million, and $113.9 million, respectively. +Keyboard sales for the years ended July 2, 2005, July 3, 2004, and June 28, 2003 were $10.1 million, $13.4 million, and $17.0 million, respectively. The remainder of revenues for all years presented were from sales of miscellaneous other products +and services. +Net sales and long-lived assets (property, plant, and equipment) +by geographic area as of and for the years ended July 2, 2005, July 3, 2004, and June 28, 2003 are summarized in the following table. Net sales set forth below are based on the shipping destination. +Domestic (U.S.) +Foreign +Total +(in thousands) +2005 +Net sales +$ +187,063 +$ +15,814 +$ +202,877 +Long-lived assets +$ +9,348 +$ +663 +$ +10,011 +2004 +Net sales +$ +134,413 +$ +14,488 +$ +148,901 +Long-lived assets +$ +10,153 +$ +978 +$ +11,131 +2003 +Net sales +$ +114,674 +$ +16,220 +$ +130,894 +Long-lived assets +$ +10,974 +$ +1,008 +$ +11,982 +For the year ended July 2, 2005, 49.9% +of the Company’s foreign net sales were to customers in Switzerland, 17.7% were to customers in Canada, 16.8 % were to customers in Mexico, 12.4% to customers in other parts of Europe, and the remaining 3.2% were spread among customers in Asia +and South America. +For the year ended July 3, 2004, 44.5% of the +Company’s foreign net sales were to customers in Mexico, 29.7% were to customers in Europe, 20.1% were to customers in Canada, and the remaining 5.7% were spread among customers in Asia and South America. +For the year ended June 28, 2003, 71.7% of the Company’s foreign net sales were to +customers in the Far East, 14.6% were to customers in Mexico, 10.0% were to customers in Europe, and the remaining 3.7% were spread among customers in Canada and South America. +33 +Table of Contents +Significant Customers +The following customers accounted for 10% or more of consolidated revenues in the three fiscal years presented below: +Fiscal Year +2005 +2004 +2003 +Lexmark International, Inc. +19 +% +14 +% +8 +% +Zebra Technologies Corporation +19 +% +12 +% +8 +% +International Game Technology, Inc. +14 +% +4 +% +0 +% +Transaction Printer Group, Inc. +9 +% +10 +% +9 +% +The Clorox Company +8 +% +16 +% +31 +% +Accounts receivable related to these +customers represented approximately 15%, 16%, 16%, 12%, and 4%, respectively of the Company’s total accounts receivable balance as of July 2, 2005. +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company +typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major +customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +10. QUARTERLY FINANCIAL DATA +(Unaudited) +Year Ended July 2, 2005 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +48,774 +$ +51,226 +$ +49,726 +$ +53,151 +Gross profit +3,548 +3,991 +4,050 +4,871 +Income before income taxes +383 +610 +762 +2,546 +Net income +266 +490 +852 +2,768 +Earnings per common share basic +0.03 +0.05 +0.09 +0.29 +Earnings per common share diluted +0.03 +0.05 +0.09 +0.28 +Weighted average shares +Basic +9,677 +9,681 +9,687 +9,692 +Diluted +9,914 +9,966 +9,901 +9,939 +Year Ended July 3, 2004 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +34,652 +$ +32,567 +$ +37,316 +$ +44,366 +Gross profit +3,355 +2,672 +3,652 +3,558 +Income (loss) before income taxes +193 +(177 +) +350 +355 +Net income (loss) +20 +(287 +) +112 +265 +Earnings (loss) per common share basic and diluted +0.00 +(0.03 +) +0.01 +0.03 +Weighted average shares +Basic +9,673 +9,673 +9,673 +9,675 +Diluted +9,775 +9,673 +9,793 +10,007 +34 +Table of Contents +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no changes in the Company’s internal controls over financial reporting during the quarter ended July 2, 2005 that have materially affected, or are reasonable +likely to materially affect, the Company’s internal control over financial reporting. +Item 9B: OTHER INFORMATION +None +35 +Table of Contents +PART III +Item 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +DALE F. PILZ – Director, Chairman of the Board +Dale F. Pilz, age 79, has served as Chairman of the Board since January 2000 and has been a director of the Company since April 1992. Mr. Pilz was Chief Executive Officer of Flowind Corporation from 1986 to 1990. He +served as President of Omninet Corporation from 1985 to 1986. Prior to that, Mr. Pilz was Chief Executive Officer and President of GTE Sprint Communications from 1983 to 1985 and also served as Chief Executive Officer and President of GTE Spacenet +Corporation from 1983 to 1985. +WENDELL J. SATRE - Director +Wendell J. Satre, age 87, has been a director of the Company since 1988 and served as +Chairman of the Board of Directors from July 1991 through August 1995. Mr. Satre also served as a director from 1983 through 1986 and served as President and CEO of the Company from August 1991 through February 1992. Mr. Satre is the retired +Chairman of the Board and Chief Executive Officer of the Washington Water Power Company (now Avista Corp.), a public utility headquartered in Spokane Valley, Washington. Mr. Satre also serves on the Board of Directors of Output Technology +Corporation and The Coeur d’Alenes Company. +YACOV A. SHAMASH - +Director +Yacov A. Shamash, age 55, has been a director of the Company since +1989. He has been the Dean of Engineering and Applied Sciences at the State University of New York campus at Stony Brook since 1992. Professor Shamash developed and directed the NSF Industry/University Cooperative Research Center for the Design of +Analog/Digital Integrated Circuits from 1989 to 1992 and also served as Chairman of the Electrical and Computer Engineering Department at Washington State University from 1985 until 1992. Dr. Shamash also serves on the Board of Directors of American +Medical Alert Corp, Manchester Technologies Inc. and Netsmart Technologies, Inc. +WILLIAM E. TERRY - Director +William E. Terry, age 72, has +been a director of the Company since August 1992. Mr. Terry retired from Hewlett-Packard in November 1993 where he served in a number of executive positions during the prior 36 years. He is a Trustee of Santa Clara University and also serves on the +Board of Directors of Altera Corporation. +PATRICK SWEENEY - +Director +Patrick Sweeney, age 70, has been a director of the Company since +July 2000. Mr. Sweeney was President and CEO of Hadco Corporation from 1991 through 1995 and formerly served as Hadco’s Vice President/Chief Financial Officer and Vice President of Operations. Prior to that Mr. Sweeney was the Vice President of +International Manufacturing at Wang - USA from 1981 through 1986 and also served as Managing Director of Ireland for Wang and as Plant Manager of its Galway and Clonmel divisions. Mr. Sweeney also serves on the Board of Directors of Aimware, Info. +Mosaic and Photo Machining Inc. +JACK W. OEHLKE - Director, President +and Chief Executive Officer +Jack W. Oehlke, age 59, has been President +and Chief Executive Officer of the Company since June 1997. From October 1995, he served as Chief Operating Officer. Previously, he served as Senior Vice President of Operations from January 1995 to October 1995 and Vice President of Manufacturing +Operations of the Company from December 1993 to January 1995. Mr. Oehlke served as Director of Operations, Director of Quality and in various management positions within manufacturing, engineering and quality functions of the Microswitch Division of +Honeywell, Inc. from 1968 to 1993. Mr. Oehlke has a Bachelor of Science Degree in Industrial Technology from the University of Wisconsin at Menomonie. +RONALD F. KLAWITTER - Executive Vice President of Administration and Chief Financial Officer +Mr. Klawitter, age 53, has been Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice +President of Finance, Secretary and Treasurer of the Company since October 1995. He was Acting Secretary from +36 +Table of Contents +November 1994 to October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President, +Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. He has a BA degree from Wittenberg University and is a Certified Public Accountant. +CRAIG D. GATES - Executive Vice President and General Manager +Mr. Gates, age 46, has been Executive Vice President and General Manager since August 2002. Previously he was Executive Vice President of Marketing, Engineering and +Sales since July 1997. He served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. Mr. Gates has a Bachelor of Science Degree +in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. From 1982 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and +from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. +EFREN R. PEREZ – Vice President of S.W. Operations +Mr. Perez, age 65, has served as Vice President of S.W. Operations since July 1997. Previously he was the Managing Director of S.W. Operations from July 1996 to July 1997 and Director of S.W. Operations from July 1995 +to June 1996. Following the Company’s acquisition of the Honeywell, Inc. Keyboard Division, Mr. Perez served as Plant Manager in Juarez from July 1993 to July 1995. He served as Plant Manager in Juarez for the Keyboard Division of Honeywell, +Inc. from February 1989 to July 1993. Mr. Perez is a graduate of the University of Mexico with a B.S. in Physics. +MICHAEL D. CHARD – Vice President of Materials +Mr. Chard, age 47, has been Vice President of Materials of the Company since July 28, 2000. From February 1999 to July 28, 2000, he held various management positions with +the Company in planning, quality assurance, and materials. From January 1997 to January 1999, he was Vice President of Product Delivery at Wang Global and its predecessor Olivetti North America. From 1983 to 1996, he held various management +positions in finance, marketing, and operations at ISC Systems, the predecessor to Olivetti North America. He holds a BA Degree in Business and Accounting from Washington State University and is a Certified Public Accountant. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2003 Proxy Statement to +Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors +and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com. The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information +appearing under the caption “Executive Compensation” in the Company’s 2005 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 2, 2005. +37 +Table of Contents +EQUITY COMPENSATION PLAN INFORMATION +Plan category +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 reflected in +column (a)) +(c) +Equity compensation plans approved by security holders +1,641,150 +$ +4.62 +84,167 +Equity compensation plans not approved by security holders (1) +344,500 +$ +2.33 +65,500 +Total +1,985,650 +$ +4.22 +149,667 +(1) +Consists of the Key Tronic Corporation 2000 Employee Stock Option Plan +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2005 Proxy Statement is incorporated +herein by this reference. +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in the Company’s 2005 Proxy Statement is incorporated herein by this +reference. +Item 14: PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2005 Proxy Statement is incorporated herein by this reference. +38 +Table of Contents +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) +1. FINANCIAL STATEMENTS +Page in +Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +19 +Consolidated Balance Sheets, as of July 2, 2005, and July 3, 2004 +20 +Consolidated Statements of Operations for the years ended July 2, 2005, July 3, 2004, and June 28, 2003 +21 +Consolidated Statements of Shareholders’ Equity for the years ended July 2, 2005, July 3, 2004, and June 28, 2003 +22 +Consolidated Statements of Cash Flows for the years ended July 2, 2005, July 3, 2004, and June 28, 2003 +23 +Notes to Consolidated Financial Statements +24-35 +2. SCHEDULES +Independent Auditors’ Report on Financial Statement Schedule +19 +II. Consolidated Valuation and Qualifying Accounts +41 +Other schedules are omitted because of +the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +3. +EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages +14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Employment Contract with Michael D. Chard, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended July 1, 2000 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.8* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.9* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.10 +Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended September 29, 2001 +10.11 +First and Second Amendments to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 29, +2002 +39 +Table of Contents +10.12 +Third Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 29, +2002 +10.13 +Fourth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 28, +2003 +10.14 +Fifth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 27, +2003 +10.15 +Sixth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended April 3, +2004 +10.16 +Seventh Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 3, +2004 +10.17 +Eighth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s From 10-K for the year ended July 3, +2004 +10.18 +Ninth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended October 2, +2004 +10.19 +Tenth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 4, 2005 +10.20 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, +2005 +10.21 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s +Form 8-K filed June 6, 2005 +10.22 +Eleventh Amendment to Financing Agreement with CIT Group Business Credit, Inc., submitted herewith +10.23* +Summary of Key Tronic Corporation Incentive Compensation Plan for fiscal year 2006, submitted herewith +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +* +Management contract or compensatory plan or arrangement +40 +Table of Contents +PART IV +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING +ACCOUNTS +FISCAL YEARS ENDED JULY 2, 2005, JULY 3, 2004, AND +JUNE 28, 2003 +2005 +2004 +2003 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +3,181 +$ +3,513 +$ +4,765 +Provisions +730 +162 +203 +Dispositions +(746 +) +(494 +) +(1,455 +) +Balance at end of year +$ +3,165 +$ +3,181 +$ +3,513 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +60 +$ +105 +$ +444 +(Recovery) provisions +140 +— +(56 +) +Write-offs +(42 +) +(45 +) +(283 +) +Balance at end of year +$ +158 +$ +60 +$ +105 +41 +Table of Contents +SIGNATURES +Pursuant to the +requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 19, 2005 +KEY TRONIC CORPORATION +By: +/s/ Jack W. Oehlke +Jack W. Oehlke, Director, President, +and Chief +Executive Officer +42 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by +the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Jack W. Oehlke +Jack W. Oehlke +(Director, President and Chief Executive Officer) +September 19, 2005 +Date +/s/ Ronald F. Klawitter +Ronald F. Klawitter (Principal Financial Officer) +September 19, 2005 +Date +/s/ Dale F. Pilz +Dale F. Pilz +(Director, Chairman of the Board) +September 19, 2005 +Date +/s/ Wendell J. Satre +Wendell J. Satre +(Director) +September 19, 2005 +Date +/s/ Yacov A. Shamash +Yacov A. Shamash +(Director) +September 19, 2005 +Date +/s/ Patrick Sweeney +Patrick Sweeney +(Director) +September 19, 2005 +Date +/s/ William E. Terry +William E. Terry +(Director) +September 19, 2005 +Date +43 \ No newline at end of file diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/filing_metadata.csv b/raw/filings/0000719733/2005/0001193125-05-188169/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..f0a70c44eaa47fc8b49abf7f5a07a56d69f50ef6 --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2005-09-20,2005-07-02,2005-09-20T16:19:23.000Z,0001193125-05-188169,d10k.htm,FORM 10-K,707810,0,0,https://www.sec.gov/Archives/edgar/data/719733/000119312505188169/d10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000119312505188169/,2005,2005,1 diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/item1.txt b/raw/filings/0000719733/2005/0001193125-05-188169/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..9718aff48bcdf1e7ee98475881888c9306c4deec --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/item1.txt @@ -0,0 +1,113 @@ +Item 1. BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, +and its subsidiaries (hereinafter collectively called the “Company”, “Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related +products manufacturing for original equipment manufacturers (OEMs). The Company also manufactures keyboards and other input devices for personal computers, terminals, and workstations primarily in standard layouts that can be sold directly from +inventory on hand. +Key Tronic is now known as an independent provider of +product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing market conditions and the Company’s strengths and capabilities, the Company +shifted its focus to EMS. The EMS industry is comprised of companies that provide a range of manufacturing services for OEMs. The EMS industry has experienced rapid growth over the past several years as more OEMs shift to outsourcing manufacturing, +and this trend is expected to continue in the future. +Operations are currently +conducted in facilities in the United States, Mexico and China. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs +and reduced product fulfillment time. +Marketing +The Company provides manufacturing services for outsourced OEM products. Key Tronic provides +a mix of EMS services including: product design, surface mount technologies (SMT) for printed circuit board assembly, tool making, precision plastic molding, liquid injection molding, prototype design, full product builds, and printing screened +silver flexible circuit membranes. +The percentage of revenues from EMS +services for the fiscal years ended July 2, 2005, July 3, 2004, and June 28, 2003 were 95.0%, 91.0% and 87.0%, respectively. Sales of such products have historically not been seasonal in nature, but may be seasonal in the future, if there are +changes in the types of products manufactured. +Although keyboard manufacturing +is still included in the Company’s product offerings, annual keyboard sales continue to decline. During the fiscal years ended July 2, 2005, July 3, 2004, and June 28, 2003, the Company realized revenues of approximately $10.1 million, $13.4 +million and $17.0 million, respectively, from the sale of keyboards representing approximately 5.0%, 9.0% and 13.0% of consolidated revenues. The keyboard market has continued to trend toward standard keyboard layouts. In order to accommodate the +demand for standard products, the Company maintains a purchase-from-stock program. The most popular standard layouts are built and stocked for immediate availability. These products serve as enhancements to or replacements for the original +system-supplied keyboards. +The Company markets its products and services +primarily through its direct sales department aided by strategically located field sales people and distributors. Although the Company establishes relationships with several independent sales organizations to assist in marketing the Company’s +EMS product lines in the U.S., commissions earned and paid are insignificant. +3 +Table of Contents +The following customers accounted for 10% or more of consolidated revenues in the three fiscal years presented below: +Fiscal Year +2005 +2004 +2003 +Lexmark International, Inc. +19 +% +14 +% +8 +% +Zebra Technologies Corporation +19 +% +12 +% +8 +% +International Game Technology, Inc. +14 +% +4 +% +0 +% +Transaction Printer Group, Inc. +9 +% +10 +% +9 +% +The Clorox Company +8 +% +16 +% +31 +% +For the fiscal years ended July 2, +2005, July 3, 2004, and June 28, 2003, the five largest customers in each year accounted for 68%, 58% and 64% of total sales, respectively. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding a capital equipment base to achieve selective vertical integration and efficiencies in its manufacturing processes. The Company +has invested significant capital into surface mount technologies (SMT) for high volume manufacturing of complex printed circuit board assemblies. The Company designs and develops tooling for injection molding and manufactures the majority of plastic +parts used in the products it manufactures. Additionally, the Company has equipment to produce printed flexible circuit membranes. +Key Tronic uses a variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated +processes include component insertion, SMT, flexible robotic assembly, computerized vision system quality inspection, automated switch and keytop installation, and automated functional testing. +The Company’s automated manufacturing processes enable it to work closely with its +customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the +tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround time during product development. +The Company purchases materials and components for its products from many different suppliers both domestic and international. Key Tronic +develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Backlog +At July 30, 2005, the Company had an order backlog of approximately $63.4 million. This compares with a backlog of approximately $68.1 million at August 1, 2004. Order backlog is not necessarily indicative of future +sales but can be indicative of trends in expected future sales revenue. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change +due to design modifications, customer forecast changes, or other customer requirements. +Research, Development, and Engineering +Research, development, +and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation and allocated information technology and facilities costs. The Company’s RD&E expenses +were $2.9 million, $2.6 million and $2.9 million in fiscal years 2005, 2004, and 2003, respectively. In each of these years, the Company focused most of its RD&E efforts on current customer EMS programs. The lower cost in fiscal year 2004 +compared to fiscal years 2005 and 2003 is due primarily to a 10% pay reduction during part of fiscal year 2004. +Competition +The market for the products and services the Company provides is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically +diverse. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and price. +Trademarks and Patents +The Key Tronic name and logo are federally registered trademarks, and the Company believes they are valuable assets of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS +Co.” to better identify its primary business concentration. The Company also owns several keyboard patents; however, since the Company’s focus is EMS, management believes that these patents will not have a significant impact on future +revenues. +4 +Table of Contents +Employees +As of July 2, 2005, the Company had 2,849 employees compared to 2,847 on July 3, 2004 and 2,687 on June 28, 2003. Since the Company can have significant fluctuations in +product demand, it seeks to maintain flexibility in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition to full-time employees. The Company’s employees in Reynosa, Mexico, are +represented by a local union. The Company has no history of any material interruption of production due to labor disputes. +The Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The Company’s employee benefits include +bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year before-tax income targets. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% of an +employee’s salary, and also provides group health, life, and disability insurance plans. The Company also maintains stock option plans and other long term incentive plans for certain employees and outside directors. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in footnote 9 of +the consolidated financial statements of this Annual Report on Form 10-K, under the caption “Enterprise-Wide Disclosures”, and that information is incorporated herein by reference. +5 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/item13.txt b/raw/filings/0000719733/2005/0001193125-05-188169/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..b4f903d8d325ac72d778cd06178547c62bc3ac6e --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/item13.txt @@ -0,0 +1,3 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information appearing under the caption “Certain Relationships and Transaction” and “Compensation Committee Interlocks and Insider Participation” in the Company’s 2005 Proxy Statement is incorporated herein by this +reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/item9a.txt b/raw/filings/0000719733/2005/0001193125-05-188169/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..d85bb9f8691e7fb35fc98acf97d9676e7bb85a52 --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/item9a.txt @@ -0,0 +1,8 @@ +Item 9A: CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no changes in the Company’s internal controls over financial reporting during the quarter ended July 2, 2005 that have materially affected, or are reasonable +likely to materially affect, the Company’s internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/rp_note.txt b/raw/filings/0000719733/2005/0001193125-05-188169/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2005/0001193125-05-188169/rpt_disclosure.txt b/raw/filings/0000719733/2005/0001193125-05-188169/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..900b74dad4ddc2e0f46407cdbfe9b75eab62c39c --- /dev/null +++ b/raw/filings/0000719733/2005/0001193125-05-188169/rpt_disclosure.txt @@ -0,0 +1,13 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +See Compensation Committee Interlocks and Insider Participation in Compensation Decisions, +page 10. +In October 2002, the Board of Directors approved retention bonus +plans for Messrs. Oehlke, Gates and Klawitter. Under the retention bonus plan, Mr. Oehlke became eligible to receive retention bonus payments in August of 2003, 2004 and 2005, if he was employed by the Company on the payment date or had been +terminated by the Company without cause. Maximum payment amounts under Mr. Oehlke’s retention bonus plan were $211,250 for 2003, $243,750 for 2004 and $276,250 for 2005. The maximum retention bonus payment in each year was reduced by the amount +of any payments earned by Mr. Oehlke pursuant to any Company incentive plans during the fiscal year immediately preceding the retention bonus payment date. +Under the retention bonus plan, Mr. Gates became eligible to receive retention bonus payments in August of 2003, 2004 and 2005 if he was employed by the Company on the +payment date or had been terminated by the Company without cause. Maximum payment amounts under Mr. Gates retention bonus plan were $119,000 for 2003, $142,800 for 2004 and $166,600 for 2005. The maximum retention bonus payment in each year was +reduced by the amount of any payments earned by Mr. Gates pursuant to any Company incentive plans during the fiscal year immediately preceding the retention bonus payment date. +Under the retention bonus plan, Mr. Klawitter became eligible to receive retention bonus payments in August of 2003, 2004 and 2005 if he was +employed by the Company on the payment date or had been terminated by the Company without cause. Maximum payment amounts under Mr. Klawitter’s retention bonus plan were $119,000 for 2003, $142,800 for 2004 and $166,600 for 2005. The maximum +retention bonus payment in each year was reduced by the amount of any payments earned by Mr. Klawitter pursuant to any Company incentive plans during the fiscal year immediately preceding the retention bonus payment date. \ No newline at end of file diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/filing.txt b/raw/filings/0000719733/2007/0001193125-07-201905/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..95a2ac8cc5cec2076b23bb13af534b282c7d19a1 --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/filing.txt @@ -0,0 +1,2872 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended June 30, 2007 +OR +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 0-11559 +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +Securities Registered Pursuant +to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +Indicate by check mark if the +registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter +period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, +to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of +“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. +Large accelerated +filer ¨ Accelerated filer ¨ Non-accelerated filer x +Indicate by +check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and +non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently +completed second fiscal quarter. As of December 31, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $40.6 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: +9,921,045 shares of common stock were outstanding as of September 3, 2007. +Documents Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 21, 2007 +Part III +Table of Contents +KEY TRONIC CORPORATION +2007 FORM 10-K +TABLE OF CONTENTS +Page +Part I +Item 1. +Business +3 - 5 +Item 1A. +Risk Factors +5 - 7 +Item 1B. +Unresolved Staff Comments +7 +Item 2. +Properties +7 +Item 3. +Legal Proceedings +8 +Item 4. +Submission of Matters to a Vote of Security Holders +8 +Part II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +8 - 9 +Item 6. +Selected Financial Data +10 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +10 - 18 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +18 - 19 +Item 8. +Financial Statements and Supplementary Data +20 - 36 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +36 +Item 9A. +Controls and Procedures +36 +Item 9B. +Other Information +36 +Part III +Item 10. +Directors, Executive Officers and Corporate Governance +37 - 38 +Item 11. +Executive Compensation +38 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +38 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +39 +Item 14. +Principal Accounting Fees and Services +39 +Part IV +Item 15. +Exhibits and Financial Statement Schedules +40 - 42 +Signatures +43 - 44 +2 +Table of Contents +FORWARD-LOOKING STATEMENTS +This Annual Report contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those +reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of +Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company +undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports +the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, and its subsidiaries (hereinafter collectively called the “Company”, +“Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related products manufacturing for original equipment manufacturers (OEMs). The Company +also manufactures keyboards and other input devices for personal computers primarily in standard layouts that can be sold directly from inventory on hand. +Key Tronic is known as an independent provider of product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing market conditions and +the Company’s strengths and capabilities, approximately eight years ago the Company shifted its strategy to focus on EMS. The EMS industry is comprised of companies that provide a range of manufacturing services for OEMs. The EMS industry has +experienced growth over the past several years as more OEMs look to outsource manufacturing, and this trend is expected to continue in the future. +Operations are currently conducted in facilities in the United States, Mexico and China. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor +costs, lower transportation costs and reduced product fulfillment time. +Marketing +The Company provides a mix of manufacturing services for outsourced OEM products. Key Tronic provides the following EMS services: product design, surface mount technologies (SMT) for printed circuit board assembly, +tool making, precision plastic molding, liquid injection molding, automated tape winding, prototype design, full product builds, and printing screened silver flexible circuit membranes. +Revenues from EMS services for the fiscal years ended June 30, 2007, July 1, 2006, and July 2, 2005 were 97.2%, 96.4% and 95.0%, respectively. Sales of the majority of the Company’s products +have historically not been seasonal in nature, but may be seasonal in the future, if there are changes in the types of products manufactured. Sales can however, fluctuate significantly between quarters from changes in customers’ demand due to +the Company’s concentration in specific customers. +The following customers accounted for 10% or more of consolidated revenues in the three fiscal +years presented below: +Fiscal Year +2007 +2006 +2005 +Zebra Technologies Corporation +22 +% +20 +% +19 +% +Lexmark International, Inc. +18 +% +17 +% +19 +% +International Game Technology, Inc. +17 +% +18 +% +14 +% +For the fiscal years ended June 30, 2007, July 1, 2006, and July 2, 2005, the five largest +customers in each year accounted for 73%, 71% and 68% of total sales, respectively. The Company’s new customer program wins may dilute its concentration of revenue to its current top five customers in the future. +Although keyboard manufacturing is still included in the Company’s product offerings, annual keyboard sales continue to decline. During the fiscal years ended +June 30, 2007, July 1, 2006, and July 2, 2005, the Company realized revenues of approximately $5.6 +3 +Table of Contents +million, $7.3 million and $10.1 million, respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, the +Company maintains a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +The Company markets +its products and services primarily through its direct sales department aided by strategically located field sales people and distributors. Although the Company maintains relationships with several independent sales organizations to assist in +marketing the Company’s EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding a capital equipment base to achieve selective vertical +integration and efficiencies in its manufacturing processes. The Company has invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies. The Company also designs and develops tooling for injection +molding and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the Company has equipment to produce printed flexible circuit membranes. +Key Tronic uses a variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, SMT, +flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, automated switch and key top installation, and automated functional testing. +The Company’s automated manufacturing processes enable it to work closely with its customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to +the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround +time during product development. +The Company purchases materials and components for its products from many different suppliers, including both domestic +and international sources. Key Tronic develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Research, Development, and Engineering +Research, development, and engineering (RD&E) expenses consist +principally of employee related costs, third party development costs, program materials costs, depreciation and allocated information technology and facilities costs. The Company’s RD&E expenses were $3.2 million, $2.8 million and $2.9 +million in fiscal years 2007, 2006, and 2005, respectively. In each of these years, the Company focused most of its RD&E efforts on current customer EMS programs. The recent increase in RD&E during fiscal 2007 is related to the Company +hiring additional program managers and engineers to transition and manage new customer program wins. +Competition +The market for the products and services the Company provides is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially +more resources and are more geographically diverse than Key Tronic. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and price. +Trademarks and Patents +The Key Tronic name and logo are federally +registered trademarks, and the Company believes they are valuable assets of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS Co.” to better identify its primary business concentration. The Company +also owns several keyboard patents; however, since the Company’s focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +As of June 30, 2007, the Company had 2,227 employees compared to 2,840 on July 1, 2006 and 2,849 +on July 2, 2005. Since the Company can have significant fluctuations in product demand, it seeks to maintain flexibility in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition +to full-time employees. The reduction in the number of employees at the end of fiscal 2007 was a result of a change in product mix that now requires less hand assembly and a reduction in forecasted sales revenue in the first quarter of 2008. The +Company’s employees in Reynosa, Mexico, which represent +4 +Table of Contents +approximately 10% of the Company’s employees, are represented by a local union. The Company has no history of any material interruption of production +due to labor disputes. +The Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The +Company’s employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. The Company regularly provides transportation, medical services and meals to all of +its employees in foreign locations. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% of an employee’s salary, and also provides group health, life, and disability insurance +plans. The Company also maintains stock option plans and other long term incentive plans for certain employees and outside directors. +Backlog +On July 28, 2007, the Company had an order backlog of approximately $34.1 million. This compares with a backlog of approximately $66.2 million on +July 29, 2006. Order backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. The change in backlog at July 28, 2007, when compared to July 29, 2006, was in part due to +the Company’s customers changing methods of issuing purchase orders to accommodate just-in-time inventory strategies. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve +months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign +Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in footnote 9 of the +consolidated financial statements of this Annual Report on Form 10-K, under the caption “Enterprise-Wide Disclosures”, and that information is incorporated herein by reference. +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect +the Company’s business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT COULD AFFECT FUTURE RESULTS +The following risks and uncertainties could affect the Company’s actual results and could cause results to differ materially from past results or those contemplated by the Company’s forward-looking statements. When used herein, +the words “expects”, “believes”, “anticipates” and similar expressions are intended to identify forward-looking statements. +Potential Fluctuations in Quarterly Results The Company’s quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including changes in overall demand for customers’ +products, success of customers’ programs, timing of new programs, new product introductions or technological advances by the Company, its customers and its competitors and changes in pricing policies by the Company, its customers, its suppliers +and its competitors. For example, the Company relies on customers’ forecasts to plan its business. If those forecasts are overly optimistic, the Company’s revenues and profits may fall short of expectations. Conversely, if those forecasts +are too conservative, the Company could have an unexpected increase in revenues and profits. The products which the Company manufactures for its customers have relatively short product lifecycles, therefore the Company’s business, operating +results and financial condition are dependent in significant part on the Company’s ability to obtain orders from new customers and new product programs from existing customers. +Competition The EMS industry is intensely competitive. Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market +share, all of which would materially and adversely affect the Company’s business, operating results and financial condition. If the Company were unable to provide comparable or better manufacturing services at a lower cost than its competitors, +it could cause sales to decline. In addition, competitors can copy the Company’s non-proprietary designs after the Company has invested in development of products for customers, thereby enabling such competitors to offer lower prices on such +products due to savings in development costs. +Concentration of Major Customers At present, the Company’s customer base is highly concentrated +and could become more or less concentrated. The Company’s largest EMS customer accounted for 22% of net sales in fiscal year 2007. This same customer accounted for 20% of sales in 2006 and 19% in 2005. For the fiscal years ended 2007, 2006, and +2005, the five largest customers +5 +Table of Contents +accounted for 73%, 71% and 68% of total sales, respectively. There can be no assurance that the Company’s principal customers will continue to purchase +products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their +orders. The Company, however, requires that its customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. The loss of one or more of the Company’s major customers, or the +reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +Dependence on Suppliers The Company is dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. Delays in +deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to the Company’s customers which could adversely affect the Company’s +operating results and damage customer relationships. +Dependence on Key Personnel The Company’s future success depends in large part on the +continued service of its key technical, marketing and management personnel and on its ability to continue to attract and retain qualified employees. The competition for such personnel is intense and there can be no assurance that the Company will be +successful in attracting and retaining such personnel. The loss of key employees could have a material adverse effect on the Company’s business, operating results and financial condition. +Foreign Manufacturing Operations Most of the products manufactured by the Company are produced at the Company’s facilities located in Mexico and China. +Accordingly, the Company’s operations are subject to a variety of risks unique to international operations including import and export duties and value added taxes, import and export regulation changes, the burden and cost of compliance with +foreign laws and foreign economic and political risk. +Technological Change and New Product Risk The markets for the Company’s customers’ +products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and relatively short product life cycles. The introduction of products embodying new technologies or the emergence of new +industry standards can render existing products obsolete or unmarketable. The Company’s success will depend upon its customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new +products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of the Company’s customers to do so could substantially harm the +Company’s customers’ competitive positions. There can be no assurance that the Company’s customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards +or evolving customer requirements. +Compliance with Current and Future Environmental Regulation The Company is subject to a variety of domestic and +foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension +of current manufactured products. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government +regulations. +Foreign Currency Fluctuations A significant portion of the Company’s operations and customers are in foreign locations. As a +result, transactions may occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by the Company could directly or indirectly affect our financial results. Future currency fluctuations are dependent upon +a number of factors and cannot be easily predicted. The Company began to use Mexican peso forward contracts in fiscal 2006 to hedge foreign currency fluctuation for a portion of weekly payroll costs. However, unexpected expenses could occur from +future fluctuations in exchange rates. +Dilution and Stock Price Volatility As of June 30, 2007, there were outstanding options for the +purchase of 1,650,838 shares of common stock of the Company (Common Stock), all of which were vested and exercisable. Holders of the Common Stock will suffer immediate and substantial dilution to the extent outstanding options to purchase the Common +Stock are exercised. The stock price of the Company may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to the Company such as variations in +quarterly operating results or changes in analysts’ earnings estimates, or to factors relating to the EMS or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often +have been unrelated to the operating performance of the specific companies whose stocks are traded. +6 +Table of Contents +Item 1B. +UNRESOLVED STAFF COMMENTS +None +Item 2. +PROPERTIES +The Company has manufacturing and sales operations +located in the United States, Mexico and China. The table below lists the locations and square footage of the Company’s operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane Valley, Washington (1) +49,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington (2) +36,000 +Leased +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +165,000 +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico (3) +60,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (4) +66,000 +Owned +Manufacturing and warehouse +Reynosa, Mexico +140,000 +Leased +Manufacturing +Reynosa, Mexico (5) +57,000 +Leased +Warehouse +Reynosa, Mexico (5) +50,000 +Leased +Warehouse +Total Mexico +547,000 +Shanghai, China (6) +72,000 +Leased +Manufacturing +Total China +72,000 +Grand Total +784,000 +(1) +On December 27, 2000, the Company sold two contiguous parcels of land and its +corporate headquarters building in Spokane to Royal Hills Associates L.L.C. (RHA) for approximately $6 million in cash. In connection with the sale, the Company entered into a 10-year lease agreement with RHA for one floor of the two-story building, +which the Company continues to occupy as its headquarters (see Note 3 to Consolidated Financial Statements). +(2) +During fiscal 2006, the Company consolidated and moved some of its molding +equipment in Spokane to its facility in Juarez, Mexico and reduced the building space leased in Spokane for manufacturing to 36,000 square feet. +(3) +In fiscal 2005, the Company purchased a 60,000 square foot manufacturing facility +in Juarez, Mexico to replace a previously leased facility and to accommodate the shift of the Las Cruces, New Mexico operations into Juarez. +(4) +In fiscal 2007, the Company purchased a 66,000 square foot manufacturing facility +in Juarez, Mexico to replace a previously leased facility. +(5) +In fiscal 2006 and 2007, the Company leased two new facilities in Reynosa, Mexico +for storage capacity. +(6) +The Company began an assembly operation in Shanghai, China in fiscal year 1999. +During fiscal year 2006, the Company increased its leased space in China to 72,000 sq. ft. to accommodate a new surface mount technology (SMT) line and additional assembly space. +The geographic diversity of these locations allows the Company to offer services near its customers and its major electronics markets, while reducing labor costs. The +Company considers the productive capacity of its current facilities sufficient to carry on the Company’s current business. In addition, the new facility in Juarez, Mexico purchased in fiscal 2007 includes adjacent vacant land that could be +developed into additional manufacturing and warehouse space. +7 +Table of Contents +Item 3. +LEGAL PROCEEDINGS +On October 24, 2002, the Company reached a +settlement in the matter of F&G Scrolling Mouse, LLC, Fernando Falcon and Frederico Gilligan v Key Tronic Corporation (“F&G”). On September 1, 2005, the Company made its final settlement payment installment to F&G in the +amount of $812,000. +The Company may be party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, +individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +Item 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Key Tronic Corporation’s common stock is +traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC”. Quarterly high and low closing sales prices for Key Tronic common stock for fiscal years 2007 and 2006 were as follows: +2007 +2006 +High +Low +High +Low +First Quarter +$ +7.16 +$ +3.98 +$ +5.47 +$ +3.50 +Second Quarter +5.85 +4.53 +4.39 +3.02 +Third Quarter +4.91 +3.88 +4.35 +3.20 +Fourth Quarter +5.55 +3.94 +4.60 +3.47 +High and low stock prices are based on the daily closing price reported by the NASDAQ Stock Market. These +quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders And Dividends +As of June 30, 2007, the Company had 909 shareholders of record. The Company’s current financing agreement +contains a covenant that prohibits the declaration or payment of dividends and the purchase of Company stock (see Note 4 to Consolidated Financial Statements). The Company has not paid a cash dividend and does not anticipate payment of dividends or +stock buyback in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance +under Equity Compensation Plans”, and that information is incorporated herein by reference. +8 +Table of Contents +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on the Company’s Common Stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic +Components Index in fiscal 2007. +9 +Table of Contents +Item 6: +SELECTED FINANCIAL DATA +The following selected consolidated +financial data of the Company should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information +included in this report. +Financial Highlights +(Dollars in thousands, except per share amounts) +Fiscal Years +2007 +2006 +2005 +2004 +2003 +Consolidated Statements of Operations Data : +Net sales +$ +201,712 +$ +187,699 +$ +202,877 +$ +148,901 +$ +130,894 +Gross profit +17,670 +17,304 +16,460 +13,237 +14,958 +Gross margin percentage +8.8 +% +9.2 +% +8.1 +% +8.9 +% +11.4 +% +Operating income +6,810 +5,861 +5,445 +1,789 +2,612 +Operating margin percentage +3.4 +% +3.1 +% +2.7 +% +1.2 +% +2.0 +% +Litigation/settlement recovery +— +— +— +— +12,186 +Net income +5,230 +9,753 +4,376 +110 +13,409 +Earnings per share – diluted +0.57 +0.97 +0.44 +0.01 +1.39 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations +(1,857 +) +(34 +) +6,561 +(17 +) +(544 +) +Capital expenditures +3,137 +1,638 +2,868 +1,633 +2,128 +Consolidated Balance Sheet Data : +Net working capital (1) +41,222 +31,703 +23,006 +23,468 +21,783 +Total assets +89,388 +88,695 +72,901 +67,938 +59,125 +Long-term liabilities +14,719 +11,665 +9,420 +13,452 +13,553 +Shareholders’ equity +43,244 +37,548 +27,639 +23,234 +23,120 +Book value per share (2) +4.36 +3.85 +2.85 +2.40 +2.39 +Supplemental Data : +Number of shares outstanding at year-end (thousands) +9,921 +9,750 +9,694 +9,676 +9,673 +Number of employees at year-end +2,227 +2,840 +2,849 +2,847 +2,687 +Approximate square footage of operational facilities +784,000 +723,000 +765,000 +786,000 +691,000 +(1) +Net working capital is defined as total current assets less total current +liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the +number of shares outstanding at the end of the fiscal year. Book value per share measures shareholders’ value as defined by generally accepted accounting principles. +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +Key Tronic Corporation is an independent provider of EMS for OEMs. The Company’s core strengths +include innovative design and engineering expertise in SMT, electronics, mechanical engineering, precision molding, design and build of molding tools, combined with high-quality, low-cost production and assembly on a global basis. The Company’s +global production capability provides customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. The Company continues to make investments in its Mexico and +China facilities which give it the production capacity and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with +Item 1A Risk Factors. +10 +Table of Contents +The EMS industry has historically experienced growth as more OEMs shift to outsourced manufacturing. However, Key +Tronic’s revenue, like that of other EMS providers’ sales revenue, can fluctuate significantly due to a reliance on a concentrated base of customers. The product demand from the Company’s largest existing customers caused an increase +in revenues during fiscal years 2005 and 2007, but these same customers saw moderate decreases in demand during fiscal 2006. +Overall, the Company’s +sales in fiscal year 2007 increased by 7.5% over fiscal 2006. The Company has recently won business with new customers that should add significant revenue in the latter part of fiscal 2008. However, sales for the first quarter of fiscal 2008 are +expected to be within the range of $42 million to $45 million, as current customer demand has decreased. Actual results will depend on actual levels of customers’ orders and the timing of the start up of production of new product programs. The +Company believes that it is well positioned in the EMS industry to expand its customer base and continue long-term growth. +The concentration of the +Company’s largest customers increased during fiscal 2007 as the top five customers’ sales increased slightly to 73% of total sales in 2007 from 71% in 2006 and 68% in 2005. The Company’s current customer relationships involve a +variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, educational toys, medical devices, exercise equipment and computer accessories. The total number of +Key Tronic EMS customers continued to increase during fiscal 2007. Some of these new customers have programs that represent small annual sales while others have multi-million-dollar potential. +Gross profit as a percent of sales was 8.8% in fiscal 2007 compared to 9.2% for the prior fiscal year. The difference in gross profit is related to certain customer +price decreases which were in excess of cost savings, a write off of $404,000 in inventory and tooling related to a customer that filed bankruptcy, and additional costs incurred in connection with the installation and start up of a new SMT line in +Spokane Valley, WA. +Net income for fiscal 2007 was $5.23 million or $0.51 per diluted share down from $9.8 million net income or $0.97 per diluted share +for fiscal 2006. The results of both years were affected by unusual events. The Company realized a gain on the sale of real estate of $1.5 million in fiscal 2007. This gain in 2007 was offset by $460,000 in costs incurred during the year in +connection with a potential acquisition that the Company chose not to pursue and the write off of $404,000 of inventory and tooling and an associated write-off of $536,000 in bad debt of a certain customer that filed bankruptcy. The Company recorded +a $5.0 million non-cash tax benefit in fiscal 2006. +The Company maintains a strong balance sheet with a current ratio of 2.31 and a long-term debt to +equity ratio of 0.31. Total cash used in operations was $1.9 million as the Company decreased its total current liabilities by approximately $8.1 million during the fiscal year. The Company maintains sufficient liquidity for its expected future +operations and had approximately $11.1 million available from its revolving line of credit based on eligible collateral at June 30, 2007. The Company maintains a good working relationship with CIT Group/Business Credit, Inc., its asset-based +lender, and the Company believes that internally generated funds and its revolving line of credit should provide adequate capital for planned growth over the long term. +The EMS industry is intensely competitive, and Key Tronic, at this time, estimates it has less than 1% of the potential market. The Company believes that it can acquire new business in the future, particularly those +programs that require innovative design and engineering, short lead times, or small initial volumes. The Company’s competitiveness is enhanced by its capacity to provide SMT, plastic injection molding, and final assembly. The Company is +planning for long term growth by utilizing current capacity, improving manufacturing processes, and investing in additional manufacturing equipment. Current challenges facing the Company include the following: continuing to win new programs, +improving operating efficiencies, controlling costs and developing competitive price strategies. +11 +Table of Contents +Results of Operations +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the +consolidated financial statements and notes contained in this Annual Report. +Years Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +Net sales +100.0 +% +100.0 +% +100.0 +% +Cost of sales +91.2 +90.8 +91.9 +Gross profit +8.8 +9.2 +8.1 +Operating expenses (income) +Research, development and engineering +1.6 +1.5 +1.4 +Selling +0.9 +1.1 +1.1 +General and administrative +3.6 +3.5 +3.4 +Gain on life insurance proceeds +0.0 +0.0 +(0.5 +) +Gain on sale of real estate held for sale +(0.7 +) +0.0 +0.0 +Operating income +3.4 +3.1 +2.7 +Interest expense +0.7 +0.6 +0.6 +Income before income taxes +2.7 +2.5 +2.1 +Income tax provision (benefit) +0.1 +(2.7 +) +0.0 +Net income +2.6 +% +5.2 +% +2.2 +% +Net Sales +Net +sales in fiscal 2007 were $201.7 million compared to $187.7 million and $202.9 million in fiscal years 2006 and 2005, respectively. +The increase in net +sales during 2007 relates to a moderate increase in the demand for certain of the Company’s largest existing customers’ products and revenue from new customers’ programs. Customers’ demand will fluctuate based on changes in the +sell-through of customers’ products. +The decline in net sales during 2006 relates to a moderate decrease in the demand for the Company’s largest +existing customers’ products from the higher level of demand seen in fiscal 2005. The Company anticipates that several new customer programs will enter production in fiscal year 2008 and begin contributing to revenue. +Cost of Sales +Total cost of sales as a percentage of net sales was +91.2%, 90.8%, and 91.9% in fiscal years 2007, 2006, and 2005, respectively. +The difference in gross profit from fiscal 2007 and 2006 is related to certain +customer price decreases in the aggregate in excess of cost savings, a write off of $404,000 in inventory and tooling related to a customer that filed for bankruptcy, and additional costs incurred in connection with the installation and start up of +a new SMT line in Spokane. The decrease in cost of sales as a percentage of net sales in 2006 from 2005 was due to production efficiencies achieved on existing customer programs together with decreases in warranty accruals and reserves for obsolete +keyboard inventory. +Total cost of materials as a percentage of sales was approximately 65.4%, 64.6%, and 67.0% in fiscal years 2007, 2006, and 2005, +respectively. The change from year-to-year is directly related to changes in product mix. Products sold in fiscal 2007 contained higher materials costs, thereby increasing costs of materials as a percentage of sales compared to fiscal 2006. +Direct production costs (direct labor and manufacturing overhead) were 13.7% of total sales in fiscal 2007 compared to 13.2% of total sales in 2006. +Direct production costs were 12.9% of total sales in 2005. Included in fiscal 2007 were start-up costs associated with the installation and start up of an SMT line at the Company’s headquarters in Spokane Valley, Washington. The SMT line in +Spokane Valley was developed for complex low volume production and for new product introduction. The increase in 2006 from 2005 is related to differences in the mix of manufactured programs. +The Company provides for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged +to expense were $544,000, $361,000, and $730,000 in fiscal years 2007, 2006, +12 +Table of Contents +and 2005, respectively. Approximately $240,000 of the provision in fiscal 2007 was related to a specific customer filing bankruptcy during the year. The +majority of the remaining provision in each year was related to domestic computer keyboards and other computer peripherals that were deemed obsolete during the year. Approximately $350,000 of the provision in 2005 was due to the decision to cease +supporting direct European sales of keyboards. +The Company provides warranties on certain products it sells and estimates warranty costs based on +historical experience and anticipated product returns. The amounts charged to expense are determined based on an estimate of warranty exposure. Warranty expense (recovery) was approximately $31,000, $(10,000), and $345,000 in fiscal years 2007, +2006, and 2005, respectively. Warranty expense for fiscal 2007 is related to workmanship claims on keyboards and certain EMS products. The recovery in 2006 related to the less than expected warranty expense related to a previously identified +workmanship issue with a particular EMS product and a decrease in the estimated future keyboard warranty costs. The majority of the warranty expense in fiscal 2005 related to a single warranty claim relating to workmanship of a particular EMS +product. +Gross Profit +In fiscal year 2007, gross +profit on sales was 8.8% of revenues compared to 9.2% in fiscal year 2006 and 8.1% in fiscal year 2005. The decrease in fiscal year 2007 relates to certain customer sales price decreases in the aggregate in excess of achieved cost savings, a write +off of $404,000 in inventory and tooling related to a customer that filed for bankruptcy, and the additional costs incurred with the installation and start up of a new SMT line in Spokane Valley, WA. The increase in gross profit as a percentage of +net sales in 2006 from 2005 was due to production efficiencies achieved on existing customer programs together with decreases in warranty accruals and reserves for obsolete keyboard inventory. Also affecting gross profits as a percentage of sales +each year are early pay discounts by the Company’s suppliers. The Company took early pay discounts that totaled $211,000, $431,000, and $132,000 in fiscal years 2007, 2006 and 2005, respectively. Early pay discounts will fluctuate based on the +Company’s liquidity and changes in the discounts offered by its suppliers. +Gross profit margins reflect the impact of a number of factors that can +vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of the Company’s resources, management of inventories, component pricing +and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that +gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation +and allocated information technology and facilities costs. The increase in RD&E in fiscal 2007 from fiscal 2006 is directly related to the hiring of new program managers to service new customer programs. As a percentage of net sales, RD&E +increased slightly in fiscal 2006 when compared to 2005. The increase as a percent of sales is due to decreasing sales with no significant decrease in costs. In each of the fiscal years presented, the Company has focused most of its RD&E efforts +on current customers’ EMS programs. +Selling +Sales and marketing expenses consist principally of salaries and benefits for sales and marketing personnel, advertising and marketing programs, sales commissions, and travel expenses. Similar to RD&E expenses, selling expenses change +as a percent of sales relative to the allocated fixed costs in each of the years presented. Approximately half of selling expense relates to fixed salary costs. +The Company’s total selling expenses were $1.8 million, $2.1 million, and $2.2 million in fiscal years 2007, 2006, and 2005, respectively. The decrease in selling expenses in 2007 from 2006 was due to the Company decreasing its outside +marketing service expense in certain months during the year. The slight decrease in 2006 from 2005 is related to a reduction in promotional programs and commissions offset in part by additional internal sales support costs. +General and Administrative +General and administrative expenses +(G&A) consist of employee related costs, travel expenses and allocated information technology and facilities costs for finance, legal, human resources and executive functions, outside legal and accounting fees, provision for doubtful accounts +and business insurance costs. As a percent of sales G&A was 3.6%, 3.5%, and 3.4% in fiscal years 2007, 2006, and 2005, respectively +13 +Table of Contents +Total G&A was $7.4 million, $6.6 million and $7.0 million in fiscal years 2007, 2006, and 2005, respectively. In 2007, the Company provided for +approximately $555,000 in bad debt expense of which $536,000 was related to a customer filing bankruptcy during the year. The Company had a provision for bad debt of $6,000 in fiscal 2006 and $140,000 in 2005. In addition $460,000 and $120,000 of +due diligence expenses, attorneys’ fees, and bank fees were expensed in fiscal 2007 and 2006, respectively, as the Company decided not to proceed with a potential acquisition. +Gain on Life Insurance Proceeds +Operating expenses in fiscal 2005 included a gain on life insurance proceeds paid on +policies insuring a former executive in the amount of $1.1 million. The Company does not hold life insurance policies on any other executives or former executives and does not anticipate any gains on life insurance proceeds in the future. +Gain on Real Estate Held for Sale +During the fourth +quarter of fiscal 2007, the Company sold its under-utilized Las Cruces, New Mexico facility. The total sales price for the facility and adjacent vacant land was $4.3 million. Sales proceeds were in the form of $2.7 million in cash and an additional +$1.5 million note from the buyer. The cash received was for the purchase of the building and approximately 9 acres of land while the note was to pay for the adjacent 14 acres of additional land. The note is payable within 45 days of the flood plain +designation being removed from the adjacent vacant land. The Company recognized a $1.5 million gain on real estate held for the sale of the building and 9 acres of land. However, due to the contingent nature of the sale of the adjacent 14 acres of +land, the Company has not recognized the sale of the additional land. A potential $951,000 gain is deferred until the note is paid. However, there is no assurance that the note will be paid in the future. +Interest Expense +The Company had net interest expenses of $1.4 +million, $1.1 million, and $1.2 million in fiscal years 2007, 2006, and 2005, respectively. Interest expense increased in 2007 when compared to fiscal 2006 and 2005 as the average balance of the revolving line of credit was higher. The higher +balance was directly attributable to higher amounts of inventory on hand during fiscal 2007. The Company does not currently use derivatives to hedge interest rate risk. Starting in 2006, the Company began to utilize short-term fixed LIBOR rates on +portions of its revolving line of credit for short-term interest savings in anticipation of rate increases. The Company successfully negotiated a variable rate decrease charged by its lender on its revolving line of credit and term debt during +fiscal year 2007. +Income Tax Provision +The Company +had an income tax provision of $206,000 in fiscal year 2007 compared to a benefit of $(5.0) million in fiscal year 2006 and a $(75,000) benefit in fiscal year 2005. The tax provision in fiscal 2007 is related to alternative minimum taxes (AMT) paid +by the Company and income taxes paid in China. The Company paid AMT due to an increase in taxable income in 2007 related to an increase in profits and an approximate $6.0 million repatriation of income from its Mexican foreign subsidiaries. +The large income tax benefit in 2006 related to the Company releasing a portion of the valuation allowance on its net deferred tax asset in accordance +with Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes . The Company has domestic tax net operating loss carryforwards (NOLs) of approximately $47.9 million at June 30, 2007. In accordance with +SFAS No. 109, management assessed the Company’s recent operating levels and the sources of future taxable income to estimate a valuation allowance. A valuation allowance against deferred tax assets is required if it is more likely than not +that some of the deferred tax assets will not be realized. Management has determined that the $12.8 million valuation allowance is appropriate. +The +benefit for fiscal year 2005 related to the Company’s Mexican subsidiaries revising intercompany agreements upon completion of new transfer pricing studies in the fourth quarter of fiscal 2005, applying certain Mexican tax credits for the +calendar years 2005 and 2004, and a reduction of Mexican statutory rates. +International Subsidiaries +The Company offers customers a complete global manufacturing solution. The Company’s facilities provide its customers the opportunity to have their products +manufactured in the facility that best serves specific cost, product manufacturing, and distribution needs. Active foreign subsidiaries are located in the following locations: +• +Key Tronic Juarez owns an SMT, assembly, and molding facility and two assembly and storage facilities in Juarez, Mexico. This subsidiary is primarily used to +support the Company’s U.S. operations. +• +Key Tronic Reynosa leases manufacturing and warehouse facilities in Reynosa, Mexico. This subsidiary is used exclusively to manufacture products for one EMS +customer. +14 +Table of Contents +• +Key Tronic Computer Peripheral Co., Ltd. leases a facility with SMT and assembly capabilities in Shanghai, China, which began operations in 1999. Its primary +function is to provide EMS services for export; however, it is also currently utilized to manufacture certain electronic keyboards. +Foreign sales (based on location of customer) from worldwide operations, including domestic exports, were $18.5 million in fiscal year 2007 compared to $13.7 million and $15.8 million in fiscal years 2006 and 2005, respectively. The +increase in foreign sales is related to a specific new foreign customer that purchased the rights to market an existing Company program. Products and manufacturing services provided by the Company’s subsidiary operations are sold to customers +directly by the parent company. Key Tronic Computer Peripheral Co., Ltd., the Company’s subsidiary in Shanghai, China, had only minimal sales to customers in China during the past three fiscal years. +Capital Resources and Liquidity +Cash flows used by operating +activities were $(1.9) million in fiscal year 2007 compared to $(34,000) used in operating activities in fiscal year 2006 and $6.6 million provided by fiscal year 2005. +The increase in cash used by operating activities in 2007 was due to primarily to a $7.1 million decrease in accounts payable offset in part by a decrease in inventory of $3.4 million. The decrease in accounts payable +at the end of fiscal 2007 was related to decreasing inventory purchases and a change in vendors’ terms. Certain new customer programs have new supply channels that require earlier payments than existing suppliers. In addition, the Company has +been effectively reducing its inventory on-hand during the last half of fiscal 2007. +Even though the Company had $9.8 million in net income in fiscal +2006, $5.0 million was in the form of a non-cash deferred income tax benefit. The Company also increased inventory levels by $6.6 million in response to forecasted increases in sales during the first quarter of 2007 and in support of transitioning +customers to RoHS compliant products. There was also a $4.8 million increase in accounts receivable due to the volume of shipments during the fourth quarter and payment of the final installment of a litigation settlement in the amount of $812,000 +offset in part by an increase in accounts payable of $5.8 million. The Company has begun to take advantage of early pay discounts available from its vendors due to higher availability on the revolving credit facility. +Cash used in investing activities includes capital expenditures. Capital expenditures were $3.1 million, $1.6 million, and $2.9 million in fiscal years 2007, 2006, and +2005, respectively. The Company’s capital expenditures are primarily for purchases of manufacturing assets to support Company operations in Mexico and China. The increase in fiscal year 2007 and 2005 capital expenditures was for purchasing +facilities in Juarez to replace leased manufacturing locations. The Company also uses a variety of operating leases to fund the purchases of manufacturing equipment. Total operating leases increased during fiscal 2007, as the Company further +utilized leases to finance new equipment purchases. +The Company’s primary financing activity in fiscal years 2007, 2006, and 2005 was borrowing and +repayment under the Company’s financing agreement with CIT Group/Business Credit, Inc. (CIT). The Company’s financing agreement with CIT provides a revolving credit facility of up to $25 million. The revolving loan is secured by the assets +of the Company. The interest rate provisions allow for a variable rate based on either the prime rate or LIBOR rate. The agreement specifies four alternative levels of margin to be added to these base rates depending on compliance with certain +financial covenants. The range of interest being paid to CIT on outstanding balances was 6.83% – 8.25% as of June 30, 2007. The financing agreement contains financial covenants that relate to total equity, earnings before interest, taxes, +depreciation and amortization, and a minimum fixed charge ratio. All but one of the financial covenants, the fixed charge ratio, have been removed by subsequent amendments to the financing agreement. The revolving loan matures August 22, 2009. +As of June 30, 2007, the Company was in compliance with its loan covenant. At June 30, 2007, the outstanding revolving loan balance was $13.1 million compared to $10.1 million at fiscal year end July 1, 2006. The loan balance +increased as the Company increased its working capital. Based on eligible collateral, approximately $11.1 million was available for drawdown from the revolving line of credit as of June 30, 2007. +15 +Table of Contents +Contractual Obligations and Commitments +In the normal course of business, the Company enters into contracts which obligate the Company to make payments in the future. +The table below sets forth the Company’s significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2008 +2009 +2010 +2011 +2012 +CIT Revolving Loan (1) +$ +13,081 +— +— +$ +13,081 +— +— +Capital and Operating Leases (2) +$ +9,170 +3,116 +2,675 +2,068 +1,299 +12 +Purchase Orders (3) +(1) +The terms of the CIT revolving loan are discussed in the consolidated financial +statements at Note 4, “Long-Term Obligations”. The Company’s current financing agreement with CIT terminates on August 22, 2009, at which time the unpaid balance of the revolving loan will become immediately payable. However, the +Company will more likely than not extend or replace its revolving loan agreement prior to that date. The amount payable on the Company’s revolving loan changes daily depending upon the amount of cash borrowed to support its operations and the +amount of customer payments received. The amount presented does not include any interest payable. Under the terms of the Company’s agreement with CIT, customers’ payments are applied against the outstanding revolving loan balance as soon +as the amounts clear through the banking system. +Under the terms of the revolving credit agreement, the Company +must meet a fixed coverage ratio financial covenant. As of June 30, 2007 the Company was in compliance with its loan covenants. Breaching this covenant could have a material impact on the Company’s operations or financial condition. +(2) +The Company maintains vertically integrated manufacturing operations in Mexico and +Shanghai, China. Such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, SMT lines, and automated insertion and test equipment for the various products the Company is +capable of producing. +In addition, the Company leases some of its administrative and manufacturing facilities. A +complete discussion of properties can be found in Part 1, Item 2 at “Properties”. Leases have proven to be an acceptable method for the Company to acquire new or replacement equipment and to maintain facilities with a minimum impact +on its short term cash flows for operations. +(3) +As of June 30, 2007, the Company had open purchase order commitments for +materials and other supplies of approximately $109 million. Included in the open purchase orders, there are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with the Company’s +manufacturing levels. In addition, the Company has contracts with its customers that minimize its exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without +penalty within specified ranges that are determined in negotiations with the Company’s suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, the Company has various other accruals which are not included. The Company owes +its suppliers approximately $24.1 million for accounts payable and shipments in transit at the end of the fiscal year. The Company generally pays its suppliers in a range from 30 to 120 days depending on terms offered. Quarterly payments to +suppliers normally average between $30 and $35 million. These payments are financed by operating cash flows and the Company’s revolving line of credit. +The Company believes that internally generated cash flows, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +Critical Accounting Policies +Revenue +Recognition : The Company recognizes revenue when products are shipped. Securities and Exchange Commission (SEC) Staff Accounting Bulletin (SAB) 104, Revenue Recognition states that revenue generally is realized or realizable and earned +when all of the following criteria are met: +• +Persuasive evidence of an arrangement exists. +• +Delivery has occurred or services have been rendered. +• +The seller’s price to the buyer is fixed or determinable. +• +Collectibility is reasonably assured. +16 +Table of Contents +The Company believes that it meets the above criteria for the following reasons: +• +Customer purchase orders confirming the price, shipping terms, and payment terms are required prior to shipment. +• +The terms of the Company’s sales are generally FOB shipping point, meaning that the customer takes ownership of the goods and assumes the risk of loss when the +goods leave the Company’s premises. +• +The seller’s price to the buyer is fixed or determinable – as noted, the Company requires customer purchase order, which confirms the price, shipping and +payment terms. +• +Collectibility is reasonably assured – the credit terms for customers are pre-established based on a review of the customers perceived ability to pay so that +collection of the account can be reasonably assured. +Inactive, Obsolete and Surplus Inventory Reserve : The Company reserves for +inventories that it deems inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that the Company produces. Demand is determined by expected sales or customer forecasts. If expected sales do not materialize, +then the Company would have inventory in excess of its reserves and would have to charge the excess against future earnings. In the case where the Company has purchased material based upon a customer’s forecast, the Company is usually covered +by lead-time assurance agreements with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If the Company +purchases material outside the lead-time assurance agreement and the customer’s forecasts do not materialize, the Company would have the financial liability and would have to charge any excess obsolete inventory against earnings. +Allowance for Doubtful Accounts : The Company values its accounts receivable net of an allowance for doubtful accounts. This allowance is based on estimates of the +portion of accounts receivable that may not be collected in the future, and the amount of this allowance is disclosed in the Company’s consolidated balance sheets. The estimates used are based primarily on specific identification of potentially +uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of the Company’s customers were to develop unexpected and immediate financial +problems that would prevent payment of open invoices, the Company could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty : An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analysis and anticipated +product returns and rework costs. As the Company has made the transition from manufacturing primarily keyboards to primarily EMS products, its exposure to warranty claims has declined significantly. The Company’s warranty period for keyboards +is generally longer than that for EMS products. Also the Company does not warrant design defects for EMS customers. +Income Taxes +The Company has domestic tax loss carryforwards of approximately $47.9 million at June 30, 2007. In accordance with SFAS No. 109, Accounting for Income +Taxes , management assesses the sources of future taxable income, which may be available to recognize the deductible differences that comprise deferred tax assets. A valuation allowance against deferred tax assets is required if it is more likely +than not that some or all of the deferred tax assets will not be realized. Management has determined that a valuation allowance of $12.8 million on the total deferred tax asset is appropriate at this time. +Goodwill +In accordance with SFAS No. 142, Goodwill and Other +Intangibles , the Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. Goodwill is tested for impairment annually. The Company adopted SFAS No. 142 on +June 30, 2002, and completed its impairment test during the second quarters of each of the subsequent fiscal years. The tests did not indicate an impairment of the Company’s stated goodwill of $765,000. +Derivatives +The Company has adopted SFAS No. 133, Accounting +for Derivative Instruments and Certain Hedging Activities , as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activity , an Amendment of SFAS 133, and SFAS No. 149 Amendment on +Statement 133 on Derivative Instruments and Hedging Activities . In accordance with these standards all derivative instruments are recorded on the balance sheet at their respective fair values. Generally, if a derivative instrument is +specifically designated as a cash flow hedge, the change in the fair value of the derivative is recorded in other comprehensive income to the extent the derivative is effective, and recognized in the statement of operations when the hedged item +affects earnings. If a derivative instrument is designated as a fair value hedge, the change in fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings in the current period. Subsequent to year +end June 30, 2007, +17 +Table of Contents +the Company entered into forward contracts to hedge transactional exposure associated with commitments arising from future cash commitments in a currency +other than the functional U.S. dollar. +New Accounting Pronouncements +In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154, Accounting Changes and Error Corrections . SFAS No. 154 provides guidance on the accounting for and reporting of +accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS +No. 154 was adopted by the Company in the first quarter of fiscal 2007 and did not have a material effect on the consolidated financial statements. +In June 2006, FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes, was issued which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in +accordance with SFAS No. 109, Accounting for Income Taxes . This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be +taken in a tax return. This Interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after +December 15, 2006. The Company does not anticipate that the provisions of FIN 48 will have a material effect on the consolidated financial statements. +In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements , which defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands the requisite +disclosure for fair value measurements. SFAS No. 157 is effective in fiscal years beginning after November 15, 2007 and is required to be adopted by the Company in the first quarter of fiscal year 2009. The Company does not anticipate a +material effect of adopting SFAS No. 157 on its consolidated financial statements. +In September 2006, the SEC released SAB No. 108, +Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements , which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should +be considered in quantifying a current year misstatement. Pursuant to SAB No. 108, registrants are required to quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in +quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB No. 108 was effective for fiscal years ending after November 15, 2006 and was applied by the Company in the current +fiscal year. The application of SAB No. 108 did not have a material impact on the Company’s consolidated results of operations and financial condition as of June 30, 2007. +In February 2007, the FASB issued SFAS No. 159, Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115 . SFAS 159 permits entities to choose to measure +certain financial instruments and certain other items at fair value at specified election dates. The fair value option may be applied instrument by instrument with certain exceptions and is applied generally on an irrevocable basis to the entire +instrument. SFAS 159 is effective in fiscal years beginning after November 15, 2007 and is required to be adopted by the Company in the first quarter of fiscal year 2009. Early adoption is permitted under certain circumstances. The Company does +not anticipate a material effect of adopting SFAS No. 159 on its consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The +Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company’s major market risk relates to its secured debt. The Company’s debt is secured by substantially all of the Company’s assets. +The interest rates applicable to the Company’s revolving loan fluctuate with the JP Morgan Chase Bank prime rate and LIBOR rates. The Company does not currently enter into derivative transactions or leveraged swap agreements. +Although the Company has international operations, the functional currency for all subsidiaries is the U.S. dollar. The Company imports raw materials that are used in +its manufacturing operations. The majority of the Company’s purchases is denominated in U.S. dollars and is paid under normal trade terms. In July 2006, the Company began to hedge its foreign currency exposure in Mexico by utilizing weekly +forward contracts to cover local payroll costs paid in Mexican pesos. There were no hedges outstanding as of June 30, 2007. +18 +Table of Contents +The table below presents principal (or notional) amounts of debt outstanding at June 30, 2007 and related weighted +average variable rates by fiscal year of maturity. The weighted average variable interest rates for fiscal years 2007 through 2012 are estimated based on current rates as of June 30, 2007. These forward rates have been increased by current +levels of margins based on the financing agreement with CIT. The Company’s long term debt could increase or decrease depending upon cash needs over the period of time that the financing agreement remains in place with CIT. The JP Morgan Chase +Bank prime rate and LIBOR will fluctuate with the market and could go up or down depending on market conditions. +(In thousands) +Fiscal Years +Total +Fair Value +June 30, 2007 +2008 +2009 +2010 +2011 +2012 +Long term debt: +Secured revolving debt +— +— +$ +13,081 +— +— +$ +13,081 +$ +13,081 +Average interest rate +— +— +6.85 +% +— +— +6.85 +% +— +19 +Table of Contents +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation and subsidiaries (the Company) as of June 30, 2007 and July 1, 2006, and +the related consolidated statements of earnings, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2007. We have also audited the schedule listed in the accompanying index. These financial +statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and +perform the audit to obtain reasonable assurance about whether the financial statements and schedule are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over +financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the +effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements +and schedule, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements and schedule. We believe that our audits provide a reasonable basis for +our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of +Key Tronic Corporation and subsidiaries at June 30, 2007 and July 1, 2006, and the results of its operations and its cash flows for each of the three years in the period ended June 30, 2007 in conformity with accounting principles +generally accepted in the United States of America. +Also, in our opinion, the schedule presents fairly, in all material respects, the information set +forth therein. +/s/ BDO Seidman, LLP +Spokane, Washington +September 14, 2007 +20 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 30, 2007 +July 1, 2006 +ASSETS +Current assets: +Cash and cash equivalents +$ +3,386 +$ +2,428 +Trade receivables, less allowance for doubtful accounts of $20 and $0 +30,383 +29,003 +Inventories +32,346 +36,338 +Other +6,532 +3,416 +Total current assets +72,647 +71,185 +Property, plant and equipment, net +11,248 +9,807 +Other assets: +Restricted cash +509 +874 +Real estate +— +1,698 +Deferred income tax assets +3,500 +3,500 +Other, net of accumulated amortization of $98 and $60 +719 +866 +Goodwill +765 +765 +Total assets +$ +89,388 +$ +88,695 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +24,104 +$ +31,228 +Accrued compensation and vacation +3,713 +4,477 +Current portion of other long-term obligations +344 +689 +Other +3,264 +3,088 +Total current liabilities +31,425 +39,482 +Long-term liabilities: +Revolving loan +13,081 +10,069 +Other long-term obligations +1,638 +1,596 +Total long-term liabilities +14,719 +11,665 +Commitments and contingencies (Notes 4 and 8) +Shareholders’ equity +Common stock, no par value, authorized 25,000 shares; issued and outstanding 9,921 and 9,750 shares +39,048 +38,582 +Retained earnings (accumulated deficit) +4,196 +(1,034 +) +Total shareholders’ equity +43,244 +37,548 +Total liabilities and shareholders’ equity +$ +89,388 +$ +88,695 +See accompanying notes to consolidated financial statements. +21 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF EARNINGS +(In thousands, except per share amounts) +Years Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +Net sales +$ +201,712 +$ +187,699 +$ +202,877 +Cost of sales +184,042 +170,395 +186,417 +Gross margin +17,670 +17,304 +16,460 +Operating expenses (income): +Research, development and engineering +3,162 +2,762 +2,880 +Selling +1,776 +2,111 +2,229 +General and administrative +7,387 +6,570 +6,966 +Gain on life insurance proceeds +— +— +(1,060 +) +Gain on sale of real estate +(1,465 +) +— +— +Operating income +6,810 +5,861 +5,445 +Interest expense, net +1,374 +1,108 +1,144 +Income before income taxes +5,436 +4,753 +4,301 +Income tax provision (benefit) +206 +(5,000 +) +(75 +) +Net income +$ +5,230 +$ +9,753 +$ +4,376 +Earnings per share: +Earnings per common share – basic +$ +0.53 +$ +1.00 +$ +0.45 +Weighted average shares outstanding – basic +9,898 +9,707 +9,684 +Earnings per common share – diluted +$ +0.51 +$ +0.97 +$ +0.44 +Weighted average shares outstanding – diluted +10,342 +10,070 +9,926 +See accompanying notes to consolidated financial statements. +22 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY +(In thousands) +Common Stock +Retained Earnings +(Accumulated +Deficit) +Total +Shares +Amount +Balances, July 3, 2004 +9,676 +$ +38,397 +$ +(15,163 +) +$ +23,234 +Exercise of stock options +18 +29 +— +29 +Net income – 2005 +— +— +4,376 +4,376 +Balances, July 2, 2005 +9,694 +38,426 +(10,787 +) +27,639 +Stock based compensation +— +40 +— +40 +Exercise of stock options +56 +116 +— +116 +Net income – 2006 +— +— +9,753 +9,753 +Balances, July 1, 2006 +9,750 +38,582 +(1,034 +) +37,548 +Stock based compensation +— +6 +— +6 +Exercise of stock options +171 +460 +— +460 +Net income – 2007 +— +— +5,230 +5,230 +Balances, June 30, 2007 +9,921 +$ +39,048 +$ +4,196 +$ +43,244 +See accompanying notes to consolidated financial statements. +23 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +Increase (decrease) in cash and cash equivalents: +Cash flows from operating activities: +Net income +$ +5,230 +$ +9,753 +$ +4,376 +Adjustments to reconcile net income to cash provided (used) by operating activities: +Depreciation and amortization +1,814 +1,890 +2,366 +Accretion of deferred gain on sale of building +(78 +) +(78 +) +(78 +) +Provision for obsolete inventory +544 +361 +730 +Provision for doubtful receivables +555 +6 +140 +Provision for (recovery of) warranty +31 +(10 +) +345 +(Gain) loss on sale of assets +(1,463 +) +(101 +) +149 +Stock based compensation expense +6 +40 +— +Deferred income tax benefit +— +(5,000 +) +— +Changes in operating assets and liabilities: +Trade receivables +(1,935 +) +(4,818 +) +108 +Inventories +3,448 +(6,987 +) +(2,594 +) +Other assets +(1,557 +) +1,084 +(1,596 +) +Accounts payable +(7,124 +) +5,753 +1,121 +Accrued compensation and vacation +(764 +) +(764 +) +1,226 +Litigation settlement +— +(812 +) +(1,649 +) +Other liabilities +(564 +) +(351 +) +1,917 +Cash provided (used) by operating activities +(1,857 +) +(34 +) +6,561 +Cash flows from investing activities: +Purchase of property and equipment +(3,137 +) +(1,638 +) +(2,868 +) +Proceeds from sale of property and equipment +2,691 +140 +8 +Cash used by investing activities +(446 +) +(1,498 +) +(2,860 +) +Cash flows from financing activities: +Payment of financing costs +(50 +) +(50 +) +(90 +) +Proceeds from exercise of stock options +460 +116 +29 +Proceeds from long-term debt +499 +— +1,500 +Repayment of long-term debt +(1,025 +) +(510 +) +(385 +) +Borrowing under revolving credit agreement +213,266 +202,168 +210,152 +Repayment of revolving credit agreement +(210,254 +) +(199,511 +) +(213,591 +) +Decrease (increase) in restricted cash +365 +284 +(453 +) +Cash provided (used) by financing activities +3,261 +2,497 +(2,838 +) +Increase in cash and cash equivalents +958 +965 +863 +Cash and cash equivalents, beginning of year +2,428 +1,463 +600 +Cash and cash equivalents, end of year +$ +3,386 +$ +2,428 +$ +1,463 +Supplemental cash flow information: +Interest payments +$ +1,303 +$ +1,100 +$ +1,100 +Income tax payments, net of refunds +$ +258 +$ +194 +$ +247 +See accompanying notes to consolidated financial statements. +24 +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is +engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs), and also manufactures keyboards and other input devices. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in Ireland, Mexico, +and China. Intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates +and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. +Significant estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, the valuation allowances on deferred tax assets, valuation of goodwill, medical self insurance liability, long-term +incentive compensation accrual and the provision for warranty costs. Actual results could differ from those estimates. +Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates +fair value. The Company has restricted cash amounts in the Company’s bank account that cannot be used for any other purpose than to pay down the Company’s long term revolving line of credit. +Allowance for Doubtful Accounts +The Company evaluates the +collectibility of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables that are +considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current +business environment, and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) +method. The Company provides for obsolete and non-saleable inventories based on specific identification of inventory against current demand forecasts and recent usage. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line +methods over the expected useful lives of the assets. Internally constructed molds and dies are depreciated over the expected useful lives of one to two years. Repairs and maintenance costs are expensed as incurred. +Impairment of Long-lived Assets +The Company, using its best +estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are +reported at the lower of cost or fair value. +25 +Table of Contents +Deferred Loan Fees +Deferred loan fees included in other assets are amortized over the term of the related loan agreement. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based +on historical analyses and anticipated product returns. +Self-funded Insurance +The Company began to self-fund its domestic employee health plan on June 30, 2004. The Company contracted with a separate administrative service company to supervise and administer the program and act as its +representative. The Company also insures for claims exceeding $65,000 and if the aggregate annual claims amount to more than 125% of expected claims for the plan year. The Company estimates its exposure for claims incurred but not paid at the end of +each reporting period and use historical information supplied by the Company’s insurance carrier and broker to estimate its liability for these claims. This liability is subject to a total limitation that varies based on employee enrollment and +factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. +Revenue +Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product under contractual terms, which are generally FOB +shipping point. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. Generally, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if +any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s +analysis of historical returns. +Revenues and associated costs from engineering design and development services, which are generally performed under +contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design and development services is approximately two percent of total revenue in fiscal years 2007 and 2006. +Shipping and Handling Fees +The Company classifies costs +associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported in net sales. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and +engineering costs associated with the production of EMS programs. Such costs are charged to expense as incurred. +Income Taxes +The Company accounts for income taxes in accordance with provisions of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income +Taxes . Under the asset and liability method prescribed by SFAS No. 109, deferred income taxes are provided for temporary differences between the financial reporting and tax bases of assets and liabilities. Deferred taxes are measured using +provisions of currently enacted tax laws. Tax credits are accounted for as a reduction of income taxes in the year the credit originates. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that +will likely be realized. The effect of changes in tax rates is recognized in the period in which the rate change occurs. Management has no future intent to repatriate remaining undistributed earnings of its foreign subsidiaries. Therefore, the +determination of the unrecognized deferred tax liability on foreign subsidiary undistributed earnings is not practicable. +Earnings Per Share +Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted +earnings per share is computed by dividing net income by the weighted average number of common and +26 +Table of Contents +common equivalent shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock +options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have +an antidilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico, China and its former operating subsidiary in Ireland is the U.S. dollar. Realized foreign currency transaction gains and losses are included in +general and administrative expenses. +Fair Value of Financial Instruments +The carrying values of financial instruments reflected on the balance sheets at June 30, 2007 and July 1, 2006, reasonably approximate their fair value. Based on the borrowing rates currently available to +the Company for loans with similar terms and average maturities, the fair value of long-term debt is estimated to be $13.6 million and $11.1 million, respectively, as of June 30, 2007 and July 1, 2006, which approximates the carrying +values. +Stock-based Compensation +Effective +July 3, 2005, the Company adopted the provisions of SFAS No. 123R, Share-Based Payment , for its share-based compensation plans. The Company previously accounted for these plans under the recognition and measurement principles of +Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations and disclosure requirements established by SFAS No. 123, Accounting for Stock-Based Compensation, as +amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure. +Under APB 25, prior to 2005 no +compensation expense was recorded in earnings for the Company’s stock options. The pro forma effects on net income and earnings per share for stock options were instead disclosed in a footnote to the financial statements. Under SFAS +No. 123R, all share-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as an expense in earnings over the requisite service period. Because the Company did not have a significant +number of non-vested options outstanding, the adoption of SFAS No. 123R did not have a material impact on operating results. +The Company adopted SFAS +No. 123R using the modified prospective method. Under this transition method, compensation cost recognized in fiscal year 2006 of $40,000 includes the cost for all share-based awards granted prior to, but not yet vested as of July 2, 2006. +This cost was based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123. Results for prior periods have not been restated. The Company did not grant any stock options in fiscal 2006 and 2007. As of +June 30, 2007, there were no unrecognized compensation costs related to remaining unvested stock options. +Reclassifications +Certain prior year amounts have been reclassified to conform with current year financial statement presentation. Such reclassifications had no impact on previously +reported net income or shareholders’ equity. +Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. Goodwill is tested for impairment annually. These tests have not indicated an impairment of the +Company’s stated goodwill of $765,000. +New Accounting Pronouncements +In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154, Accounting Changes and Error Corrections . SFAS No. 154 provides guidance on the accounting for and reporting of +accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS +No. 154 was adopted by the Company in the first quarter of fiscal 2007 and did not have a material effect on the consolidated financial statements. +27 +Table of Contents +In June 2006, FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes, was issued which +clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes . This Interpretation prescribes a recognition threshold and +measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on de-recognition, classification, interest and penalties, +accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not anticipate that the provisions of FIN 48 will have a material effect on the +consolidated financial statements. +In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements , which defines fair value, +establishes a framework for measuring fair value under generally accepted accounting principles, and expands the requisite disclosure for fair value measurements. SFAS No. 157 is effective in fiscal years beginning after November 15, 2007 +and is required to be adopted by the Company in the first quarter of fiscal year 2009. The Company does not anticipate a material effect of adopting SFAS No. 157 on its consolidated financial statements. +In September 2006, the Securities and Exchange Commission (SEC) released Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year +Misstatements when Quantifying Misstatements in Current Year Financial Statements , which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current +year misstatement. Pursuant to SAB No. 108, registrants are required to quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all +relevant quantitative and qualitative factors are considered, is material. SAB No. 108 was effective for fiscal years ending after November 15, 2006 and was applied by the Company in the current fiscal year. The application of SAB +No. 108 did not have a material impact on the Company’s consolidated results of operations and financial condition as of June 30, 2007. +In +February 2007, the FASB issued SFAS No. 159, Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115 . SFAS 159 permits entities to choose to measure certain financial instruments and +certain other items at fair value at specified election dates. The fair value option may be applied instrument by instrument with certain exceptions and is applied generally on an irrevocable basis to the entire instrument. SFAS 159 is effective in +fiscal years beginning after November 15, 2007 and is required to be adopted by the Company in the first quarter of fiscal year 2009. Early adoption is permitted under certain circumstances. The Company does not anticipate a material effect of +adopting SFAS No. 159 on its consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2007, 2006, and 2005 ended on June 30, 2007, July 1, 2006, and July 2, +2005, respectively. Fiscal year 2008 will end on June 28, 2008. Fiscal 2007, 2006 and 2005 were 52 week years. +2. INVENTORIES +Components of inventories were as follows: +June 30, 2007 +July 1, 2006 +(in thousands) +Finished goods +$ +6,757 +$ +5,429 +Work-in-process +3,486 +3,026 +Raw materials +22,314 +29,552 +Reserve for obsolescence +(211 +) +(1,669 +) +$ +32,346 +$ +36,338 +3. PROPERTY, PLANT AND EQUIPMENT +Life +June 30, 2007 +July 1, 2006 +(in years) +(in thousands) +Land +— +$ +970 +$ +970 +Buildings and improvements +3 to 30 +13,045 +11,107 +Equipment +1 to 10 +38,945 +38,170 +Furniture and fixtures +3 to 5 +5,050 +5,261 +58,010 +55,508 +Accumulated depreciation +(46,762 +) +(45,701 +) +$ +11,248 +$ +9,807 +28 +Table of Contents +During the fourth quarter of fiscal 2007, the Company sold its under-utilized Las Cruces, New Mexico facility. The total +sales price for the facility and adjacent vacant land was $4.3 million. Sales proceeds were in the form of $2.7 million in cash and an additional $1.5 million note from the buyer. The cash received was for the purchase of the building and +approximately 9 acres of land while the note was to pay for the adjacent 14 acres of additional land. The note is payable within 45 days of the flood plain designation being removed from the adjacent vacant land. The Company recognized a $1.5 +million gain on real estate held for sale of the building and 9 acres of land. However, due to the contingent nature of the sale of the adjacent 14 acres of land, the Company has not recognized the sale of the additional land. A potential $951,000 +gain is deferred until the note is paid. However, there is no assurance that the note will be paid in the future. +In December 2000, the Company sold its +headquarters building, located in Spokane, Washington. In conjunction with the sale, the Company entered into a ten year lease back agreement for a portion of the building. The gain on the sale of the building was deferred under other long-term +obligations and is amortized to offset lease expenses over the remaining lease term. +4. LONG-TERM DEBT +The Company has entered into a financing agreement with CIT Group/Business Credit, Inc. (CIT) which provides a revolving credit facility up to $25 million secured by the +assets of the Company. The interest rate provisions allow for a variable rate based on either the prime rate or a set LIBOR rate on specific short term traunches. The agreement specifies four alternative levels of margin to be added to these base +rates depending on compliance with certain financial covenants. The range of interest being paid to CIT on outstanding balances was 6.83%—8.25% as of June 30, 2007 and 7.46%—8.25% as of July 1, 2006. The Company successfully +negotiated a decrease in the level of margin added in a loan agreement amendment signed in August 2006. The agreement contains financial covenants that relate to total equity, earnings before interest, taxes, depreciation and amortization, and a +minimum fixed charge ratio. All but one of the financial covenants, the minimum fixed charge ratio, have been removed by subsequent amendments to the financing agreement as of August 2006. The revolving loan matures August 22, 2009. As of +June 30, 2007, the Company was in compliance with the remaining financial covenant. At June 30, 2007, the outstanding revolving loan balance was $13.1 million compared to $10.1 million at fiscal year end July 1, 2006. Based on +eligible collateral, approximately $11.1 million was available to draw from the revolving line of credit as of June 30, 2007. +In addition to the +Company’s revolving credit facility payment obligations, the Company had outstanding a $1.0 million term loan from CIT which was included in other long term liabilities as of July 1, 2006. This credit facility was paid in full upon the +sale of the Las Cruces facility in May 2007. +5. INCOME TAXES +Income tax expense (benefit) consists of the following: +Year Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +(in thousands) +Current income tax expense (benefit): +United States +$ +154 +$ +— +$ +— +Foreign +52 +— +(75 +) +206 +— +(75 +) +Deferred income tax expense: +United States +3,695 +2,250 +900 +Foreign +— +— +— +3,695 +2,250 +900 +Change in valuation allowance +(3,695 +) +(7,250 +) +(900 +) +— +(5,000 +) +— +Total income tax expense (benefit) +$ +206 +$ +(5,000 +) +$ +(75 +) +The Company had an income tax provision of $206,000 in fiscal year 2007 compared to a benefit of $(5.0) million in +fiscal year 2006 and a $(75,000) benefit in fiscal year 2005. The tax provision in fiscal 2007 is related to alternative minimum taxes (AMT) +29 +Table of Contents +paid by the Company and income taxes paid in China. The Company paid AMT due to an increase in taxable income in 2007 related to an increase in profits and +an approximate $6.0 million repatriation of income from its Mexican foreign subsidiaries. +The large income tax benefit in 2006 related to the Company +releasing a portion of the valuation allowance on its net deferred tax asset in accordance with SFAS No. 109, Accounting for Income Taxes . The Company has domestic tax net operating loss carryforwards (NOLs) of approximately $47.9 +million at June 30, 2007. In accordance with SFAS No. 109, management assessed the Company’s recent operating levels and the sources of future taxable income to estimate a valuation allowance. A valuation allowance against deferred +tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Management has determined that the $12.8 million valuation allowance is appropriate. +The benefit for fiscal year 2005 related to the Company’s Mexican subsidiaries revising intercompany agreements upon completion of new transfer pricing studies in +the fourth quarter of fiscal 2005, applying certain Mexican tax credits for the calendar years 2005 and 2004, and a reduction of Mexican statutory rates. +The Company does not provide for domestic income taxes on the undistributed earnings of its foreign subsidiaries, due to the fact that unremitted earnings are not intended by management to be repatriated in the foreseeable future. If such +earnings were subsequently recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes in foreign jurisdictions. Determination of the amount of the unrecognized deferred tax +liability on these undistributed earnings is not practicable. +The Company’s effective tax rate differs from the federal tax rate as follows: +Year Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +(in thousands) +Federal income tax expense at statutory rates +$ +1,848 +$ +1,616 +$ +1,462 +Effect of foreign vs. domestic taxes +(636 +) +(550 +) +(574 +) +State tax (net of federal effect) +54 +48 +43 +Life insurance +— +— +(274 +) +Expired NOLs +447 +1,176 +— +Repatriation of accumulated foreign subsidiary income +2,048 +— +— +Other +140 +(40 +) +168 +Change in valuation allowance +(3,695 +) +(7,250 +) +(900 +) +Income tax provision (benefit) +$ +206 +$ +(5,000 +) +$ +(75 +) +The domestic and foreign components of income before income taxes were: +Year Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +(in thousands) +Domestic +$ +3,420 +$ +3,181 +$ +2,874 +Foreign +2,016 +1,572 +1,427 +Income before income taxes +$ +5,436 +$ +4,753 +$ +4,301 +30 +Table of Contents +Deferred income taxes result from temporary differences in the timing of recognition of revenue and expenses. Deferred +income tax assets and liabilities consist of the following at: +June 30, 2007 +July 1, 2006 +(in thousands) +Inventory +$ +533 +$ +1,107 +Vacation accrual +312 +320 +Other +218 +205 +Net operating loss carryforwards +1,700 +1,095 +Current deferred income tax assets +2,763 +2,727 +Current portion of valuation allowance +(1,263 +) +(1,227 +) +Current deferred income tax assets, net of valuation allowance +$ +1,500 +$ +1,500 +Depreciation and amortization +$ +(966 +) +$ +(740 +) +State deferred taxes +414 +524 +Net operating loss carryforwards +14,595 +18,313 +Tax credit carryforwards +515 +388 +Other +434 +238 +Noncurrent deferred income tax assets +14,992 +18,723 +Valuation allowance, net of current portion +(11,492 +) +(15,223 +) +Noncurrent deferred income tax assets, net of valuation allowance +$ +3,500 +$ +3,500 +Total deferred income tax assets +$ +5,000 +$ +5,000 +At June 30, 2007, the Company had NOLs of approximating $47.9 million. The remaining net operating loss +carryforwards expire in varying amounts through 2025. Utilization of NOLs would be limited in the event the Company’s ownership changes more than 50% in a three-year period. The Company also has general business credits and alternative minimum +tax credits approximating $147,000 and $368,000, respectively. The general business credits expire in varying amounts through fiscal year 2009 and the alternative minimum tax credits do not expire. +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated +by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive +common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share options that were not included. These antidilutive securities occur when options outstanding +have an option price greater than the average market price for the period. +Years Ended +June 30, 2007 +July 1, 2006 +July 2, 2005 +Total weighted average shares – basic +9,898,009 +9,707,020 +9,684,399 +Effect of dilutive common stock options +444,457 +362,871 +241,355 +Total weighted average shares – diluted +10,342,466 +10,069,891 +9,925,754 +Antidilutive options not included in diluted earnings per share +397,750 +896,800 +930,150 +7. STOCK OPTION AND BENEFIT PLANS +The Company has two executive stock option plans for certain key employees. One plan has terminated. Options under these plans vest over one to five years and become exercisable as they vest. Options under the plans +become exercisable in full immediately prior to the occurrence of a “Change in Control” as defined in the plan documents. The Company has reserved 2,795,000 shares for issuance under these plans. As of June 30, 2007, 1,423,583 options +were outstanding all of which were exercisable. There are 68,500 shares available for future grant under the unexpired plan. These options expire five to ten years from the date of grant or date of vesting. +31 +Table of Contents +The Company also has a stock option plan for “Nonemployee Directors.” Options under this plan vest over a +three-year period and are exercisable as they vest. The Company has reserved 300,000 shares for issuance under this plan. As of June 30, 2007, 227,255 options were outstanding all of which were exercisable. The plan has terminated and no more +options can be granted under this plan. Outstanding options expire five to ten years from the date of grant or date of vesting. +On July 3, 2005, the +Company adopted SFAS No. 123R and compensation expense for options totaled approximately $6,000 and $40,000 in fiscal 2007 and 2006, respectively. There was no compensation expense incurred in conjunction with options vesting in fiscal year +2005. +The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair-value recognition provisions +of SFAS No. 123 to all of its share-based compensation awards for periods prior to the adoption of SFAS No. 123R, (in thousands, except per share data): +Year Ended July 2, 2005 +(in thousands, except +per share information) +Net income as reported +$ +4,376 +Add: Stock-based employee compensation expense included in reported net income +— +Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards +(93 +) +Pro forma net income +$ +4,283 +Earnings per share: +Basic – as reported +$ +0.45 +Diluted – as reported +$ +0.44 +Basic – pro forma +$ +0.44 +Diluted – pro forma +$ +0.43 +The following table summarizes option activity from July 1, 2006 through June 30, 2007: +Shares +Available +For Grant +Options +Outstanding +Aggregate +Intrinsic Value +(in thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life +Balance at July 1, 2006 +68,500 +1,925,450 +$ +1,422 +$ +4.28 +3.6 +Options canceled and expired +— +(103,980 +) +$ +10.08 +Options exercised +— +(170,632 +) +$ +398 +$ +2.70 +Balance at June 30, 2007 +68,500 +1,650,838 +$ +2,359 +$ +4.08 +2.6 +Exercisable at June 30, 2007 +1,650,838 +$ +2,359 +$ +4.08 +2.6 +32 +Table of Contents +The following is a summary of plan activity: +Price Range +Number +Of Options +Weighted Average +Exercise Price +Outstanding, July 3, 2004 +$ +1.15 to $ 16.25 +2,071,891 +$ +4.33 +Granted during 2005 +$ +2.96 to $ 3.40 +29,650 +$ +3.33 +Exercised +$ +1.15 to $ 2.81 +(18,000 +) +$ +1.61 +Canceled +$ +1.15 to $ 9.50 +(97,891 +) +$ +6.78 +Outstanding, July 2, 2005 +$ +1.15 to $ 16.25 +1,985,650 +$ +4.22 +Exercised during 2006 +$ +1.15 to $ 2.81 +(56,500 +) +$ +2.04 +Canceled +$ +5.03 to $ 5.63 +(3,700 +) +$ +5.14 +Outstanding July 1, 2006 +$ +1.15 to $ 16.25 +1,925,450 +$ +4.28 +Exercised during 2007 +$ +1.20 to $3.94 +(170,632 +) +$ +2.70 +Canceled +$ +3.40 to $ 16.25 +(103,980 +) +$ +10.08 +Outstanding, June 30, 2007 +$ +1.15 to $ 16.25 +1,650,838 +$ +4.08 +Additional information regarding options outstanding as of June 30, 2007, is as follows: +Options +Outstanding +Options +Exercisable +Range of +Exercise Prices +Number +Outstanding +Weighted Avg. +Remaining +Contractual +Life (yrs.) +Weighted +Avg. Exercise +Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$ 1.15 -1.73 +97,500 +3.2 +$ +1.17 +97,500 +$ +1.17 +1.74 -2.60 +143,333 +3.1 +2.09 +143,333 +2.09 +2.61 - 3.92 +622,255 +3.4 +2.81 +622,255 +2.81 +3.93 - 5.89 +662,000 +1.9 +5.08 +662,000 +5.08 +5.90 - 8.85 +93,250 +2.3 +7.34 +93,250 +7.34 +13.31 -16.25 +32,500 +0.1 +16.25 +32,500 +16.25 +$ 1.15 - 16.25 +1,650,838 +2.6 +$ +4.08 +1,650,838 +$ +4.08 +The Company also has a defined contribution plan (401(k)) available to U.S. employees who have attained age +21. The Company contributes an amount equal to 100% of the employee’s contribution on the first 3% of the employee’s compensation and an additional 50% of the employee’s contribution on the following 2% of the employee’s +compensation. Company contributions to the plan were $427,000, $418,000, and $380,000 in fiscal years 2007, 2006 and 2005, respectively. +8. COMMITMENTS +AND CONTINGENCIES +Leases: As of June 30, 2007, the Company had $496,000 of property and equipment financed under capital leases. The +related accumulated depreciation for these capital leases amounted to $53,000 as of June 30, 2007. The Company also has operating leases for certain equipment and production facilities, which expire at various dates during the next five years. +Future minimum payments under non-cancelable operating and capital leases with initial or remaining terms of one year or more at June 30, 2007, are summarized as follows (in thousands): +33 +Table of Contents +Fiscal Years Ending +Operating +Leases +Capital +Leases +2008 +$ +2,918 +$ +198 +2009 +2,478 +197 +2010 +1,902 +166 +2011 +1,299 +— +2012 +12 +— +Total minimum lease payments +$ +8,609 +561 +Amount representing interest +(6 +) +Present value of lease payments +555 +Current portion +198 +Capital lease obligations, net of current portion +$ +357 +Rental expenses under operating leases were approximately $4.4 million, $4.3 million, and $4.5 million in 2007, +2006, and 2005, respectively. +Warranty Costs: The Company provides warranties on certain product sales and allowances for estimated warranty costs +are recorded during the period of sale. The determination of such allowances requires us to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company currently establishes warranty +reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. +Components of the reserve for warranty costs during 2007, 2006 and 2005 were as follows: +Balance at July 3, 2004 +$ +173,732 +Additions related to current period sales +345,226 +Warranty costs incurred in the period +(273,103 +) +Balance at July 2, 2005 +245,855 +Recovery related to current period sales +(9,900 +) +Warranty costs incurred in the period +(145,955 +) +Balance at July 1, 2006 +90,000 +Additions related to current period sales +30,680 +Warranty costs incurred in the period +(80,680 +) +Balance at June 30, 2007 +$ +40,000 +Litigation : The Company may be party to certain lawsuits or claims in the ordinary course of business. The +Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s Bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against +certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and +officers and former directors in certain circumstances. +34 +Table of Contents +9. ENTERPRISE-WIDE DISCLOSURES +Management organizes its business around EMS and keyboards based on geographic area. These businesses have been aggregated into one segment as each has similar economic characteristics, and the nature of the business, +its production processes, customers and distribution methods are similar. +Of the revenues for the years ended June 30, 2007, July 1, 2006, +and July 2, 2005, EMS sales were $196.1 million, $180.4 million, and $192.8 million, respectively. Keyboard sales for the years ended June 30, 2007, July 1, 2006, and July 2, 2005 were $5.6 million, $7.3 million, and $10.1 +million, respectively. +Net sales and long-lived assets (property, plant, and equipment) by geographic area as of and for the years ended June 30, +2007, July 1, 2006, and July 2, 2005 are summarized in the following table. Net sales set forth below are based on the shipping destination. +Domestic (U.S.) +Foreign +Total +(in thousands) +2007 +Net sales +$ +183,261 +$ +18,451 +$ +201,712 +Long-lived assets +$ +9,866 +$ +1,382 +$ +11,248 +2006 +Net sales +$ +173,978 +$ +13,721 +$ +187,699 +Long-lived assets +$ +8,184 +$ +1,623 +$ +9,807 +2005 +Net sales +$ +187,063 +$ +15,814 +$ +202,877 +Long-lived assets +$ +9,348 +$ +663 +$ +10,011 +For the year ended June 30, 2007, 43.4% of the Company’s foreign net sales were to customers in +Switzerland, 46.3% were to Asia, 9.2% were to Canada, and the remaining 1.1% were spread among customers in other parts of Europe and Australia. +For the +year ended July 1, 2006, 56.3% of the Company’s foreign net sales were to customers in Switzerland, 23.8% were to Asia, 13.2% were to Canada, and the remaining 6.7% were spread among customers in other parts of Europe and Australia. +For the year ended July 2, 2005, 49.9% of the Company’s foreign net sales were to customers in Switzerland, 17.7% were to customers in Canada, +16.8% were to customers in Mexico, 12.4% to customers in other parts of Europe, and the remaining 3.2% were spread among customers in Asia and South America. +Significant Customers +The following customers accounted for 10% or more of consolidated revenues in the three fiscal years presented below: +Fiscal Year +2007 +2006 +2005 +Zebra Technologies Corporation +22 +% +20 +% +19 +% +Lexmark International, Inc. +18 +% +17 +% +19 +% +International Game Technology, Inc. +17 +% +18 +% +14 +% +Accounts receivable related to these customers represented approximately 23%, 18%, and 15%, respectively of the +Company’s total accounts receivable balance as of June 30, 2007. +There can be no assurance that the Company’s principal customers will +continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the +shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and +financial condition. +35 +Table of Contents +10. QUARTERLY FINANCIAL DATA +(Unaudited) +Year Ended June 30, 2007 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +55,512 +$ +49,829 +$ +47,212 +$ +49,159 +Gross profit +5,294 +4,201 +3,720 +4,455 +Income before income taxes +1,484 +366 +723 +2,863 +Net income +1,419 +345 +742 +2,724 +Earnings per common share-basic +.14 +.03 +.07 +.27 +Earnings per common share-diluted +.14 +.03 +.07 +.26 +Weighted average shares outstanding +Basic +9,842 +9,915 +9,915 +9,920 +Diluted +10,458 +10,390 +10,272 +10,302 +Year Ended July 1, 2006 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +44,250 +$ +45,360 +$ +45,567 +$ +52,522 +Gross profit +3,852 +4,100 +3,977 +5,375 +Income before income taxes +709 +1,011 +917 +2,116 +Net income +702 +1,018 +917 +7,116 +Earnings per common share-basic +0.07 +0.10 +0.09 +0.73 +Earnings per common share-diluted +0.07 +0.10 +0.09 +0.71 +Weighted average shares outstanding +Basic +9,696 +9,703 +9,705 +9,724 +Diluted +10,140 +10,022 +10,064 +10,093 +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no significant changes in the Company’s internal controls over financial reporting during the quarter ended June 30, 2007 that have materially affected, or +are reasonable likely to materially affect, the Company’s internal control over financial reporting. +Item 9B: +OTHER INFORMATION +None +36 +Table of Contents +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +JAMES R. +BEAN —Director +James R. Bean, age 57, has been President and CEO of Preco Electronics, Inc. since November 1999. From May 1997 to 1999 he held +various management positions in Boise, Idaho with Preco Electronics, Inc. Previously he held various management positions in manufacturing operations with Sun Microsystems, Inc., Apple Computer, Inc. and National Semiconductor, Inc. Mr. Bean is +a graduate of New Mexico State University with a B.S. in Industrial Engineering. +DALE F. PILZ —Director, Chairman of the Board +Dale F. Pilz, age 81, has served as Chairman of the Board since January 2000 and has been a director of the Company since April 1992. Mr. Pilz was Chief Executive +Officer of Flowind Corporation from 1986 to 1990. He served as President of Omninet Corporation from 1985 to 1986. Prior to that, Mr. Pilz was Chief Executive Officer and President of GTE Sprint Communications from 1983 to 1985 and also served +as Chief Executive Officer and President of GTE Spacenet Corporation from 1983 to 1985. +YACOV A. SHAMASH —Director +Yacov A. Shamash, age 57, has been a director of the Company since 1989. He has been the Dean of Engineering and Applied Sciences at the State University of New York +campus at Stony Brook since 1992. Professor Shamash developed and directed the NSF Industry/University Cooperative Research Center for the Design of Analog/Digital Integrated Circuits from 1989 to 1992 and also served as Chairman of the Electrical +and Computer Engineering Department at Washington State University from 1985 until 1992. Dr. Shamash also serves on the Board of Directors of American Medical Alert Corp, Netsmart Technologies, Inc., and APDN. +PATRICK SWEENEY —Director +Patrick Sweeney, age 72, has been a +director of the Company since July 2000. Mr. Sweeney was President and CEO of Hadco Corporation from 1991 through 1995 and formerly served as Hadco's Vice President/Chief Financial Officer and Vice President of Operations. Prior to that +Mr. Sweeney was the Vice President of International Manufacturing at Wang—USA from 1981 through 1986 and also served as Managing Director of Ireland for Digital and as Plant Manager of its Galway and Clonmel divisions. Mr. Sweeney +also serves on the Board of Directors of Aimware, Info. Mosaic and Photo Machining Inc. +JACK W. OEHLKE —Director, President and Chief Executive +Officer +Jack W. Oehlke, age 61, has been President and Chief Executive Officer of the Company since June 1997. From October 1995, he served as Chief +Operating Officer. Previously, he served as Senior Vice President of Operations from January 1995 to October 1995 and Vice President of Manufacturing Operations of the Company from December 1993 to January 1995. Mr. Oehlke served as Director of +Operations, Director of Quality and in various management positions within manufacturing, engineering and quality functions of the Microswitch Division of Honeywell, Inc. from 1968 to 1993. Mr. Oehlke has a Bachelor of Science Degree in +Industrial Technology from the University of Wisconsin at Menomonie. +RONALD F. KLAWITTER —Executive Vice President of Administration and Chief +Financial Officer +Mr. Klawitter, age 55, has been Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was +Vice President of Finance, Secretary and Treasurer of the Company since October 1995. He was Acting Secretary from November 1994 to October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, +Mr. Klawitter was Vice President, Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. He has a BA degree from Wittenberg University and is a Certified Public Accountant. +CRAIG D. GATES —Executive Vice President and General Manager +Mr. Gates, age 48, has been Executive Vice President and General Manager since August 2002. Previously he was Executive Vice President of Marketing, Engineering and Sales since July 1997. He served as Vice President and General Manager +of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of +37 +Table of Contents +1994. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, +Urbana. From 1982 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. +EFREN R. PEREZ —Vice President of S.W. Operations +Mr. Perez, age 67, has served as Vice President of S.W. Operations since July 1997. Previously he was the Managing Director of S.W. Operations from July 1996 to July 1997 and Director of S.W. Operations from July 1995 to June 1996. +Following the Company’s acquisition of the Honeywell, Inc. Keyboard Division, Mr. Perez served as Plant Manager in Juarez from July 1993 to July 1995. He served as Plant Manager in Juarez for the Keyboard Division of Honeywell, Inc. from +February 1989 to July 1993. Mr. Perez is a graduate of the University of Mexico with a B.S. in Physics. +GEORGE R. ALFORD —Vice President +of Materials +George R. Alford, age 54, has been Vice President of Materials of the Company since July 2006. From August 2005 to July 2006 he served as +Director of Materials (HID Group) at Cooper Industries. From October 2000 to August 2005, he served in various procurement and materials management positions with Solectron Corporation. Mr. Alford has a B.S. in Industrial Technology and a M.A. +in Management from Middle Tennessee State University and a J.D. in Civil Law from Nashville School of Law. +Compliance with Section 16(a) of the +Exchange Act: +Incorporated by reference to Key Tronic Corporation's 2003 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of +Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or +waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption +“Executive Compensation” in the Company’s 2007 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 30, 2007. +EQUITY COMPENSATION PLAN INFORMATION +Plan category +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 reflected in +column (a)) +(c) +Equity compensation plans approved by security holders +1,423,005 +$ +4.38 +0 +Equity compensation plans not approved by security holders (1) +227,833 +$ +2.21 +68,500 +Total +1,650,838 +$ +4.08 +68,500 +(1) +Consists of the Key Tronic Corporation 2000 Employee Stock Option Plan +38 +Table of Contents +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2007 Proxy Statement +is incorporated herein by this reference. +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation” and “Directors’ Independence” in the Company’s 2007 Proxy Statement +is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under +the caption “Principal Accountant Fees and Services” in the Company’s 2007 Proxy Statement is incorporated herein by this reference. +39 +Table of Contents +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL +STATEMENTS +Page in +Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +20 +Consolidated Balance Sheets, as of June 30, 2007, and July 1, 2006 +21 +Consolidated Statements of Earnings for the years ended June 30, 2007, July 1, 2006, and July 2, 2005 +22 +Consolidated Statements of Shareholders’ Equity for the years ended June 30, 2007, July 1, 2006, and July 2, 2005 +23 +Consolidated Statements of Cash Flows for the years ended June 30, 2007, July 1, 2006, and July 2, 2005 +24 +Notes to Consolidated Financial Statements +25-36 +2. SCHEDULES +Report of Independent Registered Public Accounting Firm on Financial Statement Schedule +20 +II. Consolidated Valuation and Qualifying Accounts +42 +Other schedules are omitted because of the absence of conditions under which they are required, or because +required information is given in the financial statements or notes thereto. +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages 14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Employment Contract with Michael D. Chard, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended July 1, 2000 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.8* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.9* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.10 +Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended September 29, 2001 +10.11 +First and Second Amendments to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 29, +2002 +40 +Table of Contents +10.12 +Third Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 29, +2002 +10.13 +Fourth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 28, +2003 +10.14 +Fifth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended December 27, 2003 +10.15 +Sixth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended April 3, +2004 +10.16 +Seventh Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 3, +2004 +10.17 +Eighth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s From 10-K for the year ended July 3, +2004 +10.18 +Ninth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended October 2, +2004 +10.19 +Tenth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 4, 2005 +10.20 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.21 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form +8-K filed June 6, 2005 +10.22* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23* the Company’s Form 10-K for the year ended July 2, 2005 +10.23* +Employment Contract between Key Tronic Corporation and George Robert Alford, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed July 26, 2006 +10.24* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2007, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.25* +Summary of Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s From 8-K filed July 28, 2006 +10.26* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +10.27 +Twelfth Amendment to Financing Agreement with CIT Group Business Credit, Inc., incorporated by reference to the Exhibit to the Company’s Form 8-K filed September 7, 2006 +10.28 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed +October 12, 2006 +10.29 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed +November 20, 2006 +10.30 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, +2007 +10.31 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.32* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated +by reference to the Company’s Form 8-K filed July 27, 2007 +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +* +Management contract or compensatory plan or arrangement +41 +Table of Contents +PART IV +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 30, 2007, JULY 1, 2006, AND +JULY 2, 2005 +2007 +2006 +2005 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +1,669 +$ +3,165 +$ +3,181 +Provisions +544 +361 +730 +Dispositions +(2,002 +) +(1,857 +) +(746 +) +Balance at end of year +$ +211 +$ +1,669 +$ +3,165 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +0 +$ +158 +$ +60 +Provisions +555 +6 +140 +Write-offs +(535 +) +(164 +) +(42 +) +Balance at end of year +$ +20 +$ +0 +$ +158 +42 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the +registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 17, 2007 +KEY TRONIC CORPORATION +By: +/s/ Jack W. Oehlke +Jack W. Oehlke, Director, President, and Chief Executive Officer +43 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by +the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Jack W. Oehlke +September 17, 2007 +Jack W. Oehlke +Date +(Director, President and Chief Executive Officer) +/s/ Ronald F. Klawitter +September 17, 2007 +Ronald F. Klawitter +Date +(Principal Financial Officer) +/s/ James R. Bean +September 17, 2007 +James R. Bean +Date +(Director) +/s/ Dale F. Pilz +September 17, 2007 +Dale F. Pilz +Date +(Director, Chairman of the Board) +/s/ Yacov A. Shamash +September 17, 2007 +Yacov A. Shamash +Date +(Director) +/s/ Patrick Sweeney +September 17, 2007 +Patrick Sweeney +Date +(Director) +44 \ No newline at end of file diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/filing_metadata.csv b/raw/filings/0000719733/2007/0001193125-07-201905/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..799ed3dbfcb0e10cbb1e5dbc846b2591adbbf6c4 --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2007-09-17,2007-06-30,2007-09-17T15:05:50.000Z,0001193125-07-201905,d10k.htm,FORM 10-K,735485,0,0,https://www.sec.gov/Archives/edgar/data/719733/000119312507201905/d10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000119312507201905/,2007,2007,1 diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/item1.txt b/raw/filings/0000719733/2007/0001193125-07-201905/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..50a7aa8abfb614462a299f5fd6ff0936ebd36eeb --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/item1.txt @@ -0,0 +1,100 @@ +Item 1. +BUSINESS +Overview +Key Tronic Corporation (dba KeyTronicEMS Co.), a Washington corporation organized in 1969, and its subsidiaries (hereinafter collectively called the “Company”, +“Key Tronic”, or “we” unless the context otherwise requires) are principally engaged in electronic manufacturing services (EMS) and consumer related products manufacturing for original equipment manufacturers (OEMs). The Company +also manufactures keyboards and other input devices for personal computers primarily in standard layouts that can be sold directly from inventory on hand. +Key Tronic is known as an independent provider of product realization services for OEMs in a variety of industries. Historically, Key Tronic was principally a manufacturer of electronic keyboards, but after assessing market conditions and +the Company’s strengths and capabilities, approximately eight years ago the Company shifted its strategy to focus on EMS. The EMS industry is comprised of companies that provide a range of manufacturing services for OEMs. The EMS industry has +experienced growth over the past several years as more OEMs look to outsource manufacturing, and this trend is expected to continue in the future. +Operations are currently conducted in facilities in the United States, Mexico and China. The Company’s global production capability provides customers with benefits of improved supply-chain management, reduced inventory, lower labor +costs, lower transportation costs and reduced product fulfillment time. +Marketing +The Company provides a mix of manufacturing services for outsourced OEM products. Key Tronic provides the following EMS services: product design, surface mount technologies (SMT) for printed circuit board assembly, +tool making, precision plastic molding, liquid injection molding, automated tape winding, prototype design, full product builds, and printing screened silver flexible circuit membranes. +Revenues from EMS services for the fiscal years ended June 30, 2007, July 1, 2006, and July 2, 2005 were 97.2%, 96.4% and 95.0%, respectively. Sales of the majority of the Company’s products +have historically not been seasonal in nature, but may be seasonal in the future, if there are changes in the types of products manufactured. Sales can however, fluctuate significantly between quarters from changes in customers’ demand due to +the Company’s concentration in specific customers. +The following customers accounted for 10% or more of consolidated revenues in the three fiscal +years presented below: +Fiscal Year +2007 +2006 +2005 +Zebra Technologies Corporation +22 +% +20 +% +19 +% +Lexmark International, Inc. +18 +% +17 +% +19 +% +International Game Technology, Inc. +17 +% +18 +% +14 +% +For the fiscal years ended June 30, 2007, July 1, 2006, and July 2, 2005, the five largest +customers in each year accounted for 73%, 71% and 68% of total sales, respectively. The Company’s new customer program wins may dilute its concentration of revenue to its current top five customers in the future. +Although keyboard manufacturing is still included in the Company’s product offerings, annual keyboard sales continue to decline. During the fiscal years ended +June 30, 2007, July 1, 2006, and July 2, 2005, the Company realized revenues of approximately $5.6 +3 +Table of Contents +million, $7.3 million and $10.1 million, respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, the +Company maintains a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +The Company markets +its products and services primarily through its direct sales department aided by strategically located field sales people and distributors. Although the Company maintains relationships with several independent sales organizations to assist in +marketing the Company’s EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +Since inception, the Company has made substantial investments in developing and expanding a capital equipment base to achieve selective vertical +integration and efficiencies in its manufacturing processes. The Company has invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies. The Company also designs and develops tooling for injection +molding and manufactures the majority of plastic parts used in the products it manufactures. Additionally, the Company has equipment to produce printed flexible circuit membranes. +Key Tronic uses a variety of manual and highly automated assembly processes in its facilities, depending upon product complexity and degree of customization. Automated processes include component insertion, SMT, +flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, automated switch and key top installation, and automated functional testing. +The Company’s automated manufacturing processes enable it to work closely with its customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to +the marketplace. Key Tronic uses computer-aided design techniques and unique software to assist in preparation of the tool design layout and tool fabrications, to reduce tooling costs, improve component and product quality, and enhance turnaround +time during product development. +The Company purchases materials and components for its products from many different suppliers, including both domestic +and international sources. Key Tronic develops close working relationships with its suppliers, many of whom have been supplying products to the Company for several years. +Research, Development, and Engineering +Research, development, and engineering (RD&E) expenses consist +principally of employee related costs, third party development costs, program materials costs, depreciation and allocated information technology and facilities costs. The Company’s RD&E expenses were $3.2 million, $2.8 million and $2.9 +million in fiscal years 2007, 2006, and 2005, respectively. In each of these years, the Company focused most of its RD&E efforts on current customer EMS programs. The recent increase in RD&E during fiscal 2007 is related to the Company +hiring additional program managers and engineers to transition and manage new customer program wins. +Competition +The market for the products and services the Company provides is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially +more resources and are more geographically diverse than Key Tronic. Key Tronic competes primarily on the basis of responsiveness, creativity, vertical production capability, quality, and price. +Trademarks and Patents +The Key Tronic name and logo are federally +registered trademarks, and the Company believes they are valuable assets of its business. During 2001, Key Tronic began operating under the trade name “KeyTronicEMS Co.” to better identify its primary business concentration. The Company +also owns several keyboard patents; however, since the Company’s focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +As of June 30, 2007, the Company had 2,227 employees compared to 2,840 on July 1, 2006 and 2,849 +on July 2, 2005. Since the Company can have significant fluctuations in product demand, it seeks to maintain flexibility in its workforce by utilizing skilled temporary and short-term contract labor in its manufacturing facilities in addition +to full-time employees. The reduction in the number of employees at the end of fiscal 2007 was a result of a change in product mix that now requires less hand assembly and a reduction in forecasted sales revenue in the first quarter of 2008. The +Company’s employees in Reynosa, Mexico, which represent +4 +Table of Contents +approximately 10% of the Company’s employees, are represented by a local union. The Company has no history of any material interruption of production +due to labor disputes. +The Company considers its employees its primary strength and makes considerable efforts to maintain a well-qualified staff. The +Company’s employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. The Company regularly provides transportation, medical services and meals to all of +its employees in foreign locations. The Company maintains a 401(k) plan for U.S. employees, which provides a matching company contribution of up to 4% of an employee’s salary, and also provides group health, life, and disability insurance +plans. The Company also maintains stock option plans and other long term incentive plans for certain employees and outside directors. +Backlog +On July 28, 2007, the Company had an order backlog of approximately $34.1 million. This compares with a backlog of approximately $66.2 million on +July 29, 2006. Order backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. The change in backlog at July 28, 2007, when compared to July 29, 2006, was in part due to +the Company’s customers changing methods of issuing purchase orders to accommodate just-in-time inventory strategies. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve +months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign +Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in footnote 9 of the +consolidated financial statements of this Annual Report on Form 10-K, under the caption “Enterprise-Wide Disclosures”, and that information is incorporated herein by reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/item13.txt b/raw/filings/0000719733/2007/0001193125-07-201905/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..d725055087adcd79d3ad9b4ad9aec8cab81043b0 --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/item13.txt @@ -0,0 +1,4 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation” and “Directors’ Independence” in the Company’s 2007 Proxy Statement +is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/item9a.txt b/raw/filings/0000719733/2007/0001193125-07-201905/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..0e5a7563df8482215ed4a7d6cb2ff4ff000d6689 --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/item9a.txt @@ -0,0 +1,9 @@ +Item 9A: +CONTROLS AND PROCEDURES +a) +As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s chief executive +officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the chief executive officer and chief +financial officer concluded that the Company’s disclosure controls and procedures are effective. +b) +There have been no significant changes in the Company’s internal controls over financial reporting during the quarter ended June 30, 2007 that have materially affected, or +are reasonable likely to materially affect, the Company’s internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/rp_note.txt b/raw/filings/0000719733/2007/0001193125-07-201905/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2007/0001193125-07-201905/rpt_disclosure.txt b/raw/filings/0000719733/2007/0001193125-07-201905/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..a357be28ac9bc3323a5805d8eaa44f7f696cf0be --- /dev/null +++ b/raw/filings/0000719733/2007/0001193125-07-201905/rpt_disclosure.txt @@ -0,0 +1,19 @@ +Related Person Transactions +In April 2007, the Board of Directors +adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested +Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may +be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent +beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last +fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent +4 +beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. +Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home +(other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In +determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an +unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. The Company had no related Party Transactions during fiscal year 2007. +Compensation Committee Interlocks and Insider Participation in Compensation Decisions +The Board of Directors has a Compensation Committee presently consisting of Messrs. Shamash and Pilz. No member of the Compensation Committee was an officer or employee of the Company or any of its subsidiaries during +fiscal year 2007. None of the executive officers of the Company has served on the Board of Directors or on the Compensation Committee of any other entity, any of whose officers served either on the Board of Directors or on the Compensation Committee +of the Company. \ No newline at end of file diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/filing.txt b/raw/filings/0000719733/2012/0001193125-12-386435/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..5d670da0cbc8fc7d18ec66d81bf399550dd18902 --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/filing.txt @@ -0,0 +1,3846 @@ +10-K +1 +d372869d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended June 30, 2012 +OR +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-11559 +KEY TRONIC +CORPORATION +(Exact name of registrant as specified in its charter) +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the +Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 +days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every +Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such +files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will +not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an +accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +¨ +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +x +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at +which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2011, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant +was $47.7 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of +the issuer’s classes of common stock, as of the latest practicable date: 10,488,856 shares of common stock were outstanding as of September 5, 2012. +Documents +Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 21, 2012 +Part III +Table of Contents +KEY TRONIC CORPORATION +2012 FORM 10-K +TABLE OF CONTENTS +Page +Part I +Item 1. +Business +3-8 +Item 1A. +Risk Factors +8-12 +Item 1B. +Unresolved Staff Comments +13 +Item 2. +Properties +13-14 +Item 3. +Legal Proceedings +14 +Item 4. +Mine Safety Disclosures +14 +Part II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +14-15 +Item 6. +Selected Financial Data +16 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +17-28 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +28 +Item 8. +Financial Statements and Supplementary Data +29-51 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +52 +Item 9A. +Controls and Procedures +52 +Item 9B. +Other Information +52 +Part III +Item 10. +Directors, Executive Officers and Corporate Governance +53 +Item 11. +Executive Compensation +53 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +54 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +54 +Item 14. +Principal Accounting Fees and Services +54 +Part IV +Item 15. +Exhibits and Financial Statement Schedule +56-59 +Signatures +60-61 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company”, “Key Tronic”, “KeyTronicEMS”, “we”, “our”, or “us” mean Key Tronic Corporation together with its +subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in +addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that +might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” +Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments +or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, +including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +2 +Table of Contents +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: +KeyTronicEMS Co.), was organized in 1969 as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for +computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth +through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on +keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to +contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, and precision plastics combined with +high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion +of the EMS industry has allowed us to continue to expand our customer base and the industries that we serve. The challenging global macroeconomic environment has had a negative impact on previously held customer programs. However, we are +successfully confronting the challenging global macroeconomic environment by controlling our costs and winning new customer programs, which allowed us to increase our profitability and maintain a strong balance sheet during the global economic +downturn. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer +portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, assembly, component selection, sourcing and procurement, worldwide +logistics, and new product testing and production all at competitive pricing due to our global footprint. +We believe that we are well +positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, centralized management, and core strengths continue to support our growth and our +customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our +customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential +customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a +concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing +challenges that we face include the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while +developing competitive pricing strategies, and successfully transitioning new program wins to full production during a time of macroeconomic uncertainty. +3 +Table of Contents +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin +through hole capability for printed circuit board assembly, tool making, precision plastic molding, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have historically not been seasonal in nature, but may be seasonal in the future if there are changes in the types +of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years ended June 30, 2012, July 2, 2011, and July 3, 2010, the five largest customers in each year accounted for 73%, 62%, +and 57% of combined total net sales, respectively. At the end of fiscal year 2012, we were generating revenue from 165 separate programs and 48 distinct customers as compared to 119 programs and 33 customers at the end of fiscal year 2011. As these +new customers’ sales ramp and new programs are won our concentration of revenue should decrease in the future. +The following table +represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales +by Fiscal Year +2012 +2011 +2010 +Customer A +29 +% +15 +% +* +% +Customer B +17 +% +16 +% +12 +% +Customer C +16 +% +16 +% +18 +Customer D +* +* +10 +% +* +Amount was less than 10% of total. +Although +keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We realized revenues of approximately $2.8 million, $3.9 million, and $4.5 million in fiscal years +2012, 2011, and 2010, respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate +availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales +people and distributors. Although we maintain relationships with several independent sales organizations to assist in marketing our EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +We have continually made +investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board +assemblies. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing +processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, +depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, automated +switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us +to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation +of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +4 +Table of Contents +We purchase materials and components for our products from many different suppliers, including both domestic +and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed +to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program +materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have +substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and +development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of +outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks and Patents +Our name and +logo are federally registered trademarks, and we believe they are valuable assets of our business. During 2001, we began operating under the trade name “KeyTronicEMS” to better identify our primary business concentration. We also own +several keyboard patents; however, since our focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +We consider our employees to be our primary strength and we make considerable +efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical +services, and meals to all of our employees in foreign locations. We maintain a 401(k) plan for U.S. employees, which provides a discretionary matching company contribution of up to 4% of an employee’s salary. We provide group health, life, and +disability insurance plans. We also maintain stock option plans and other long term incentive plans for certain employees and outside directors. +As of June 30, 2012 we had 2,700 employees compared to 1,997 on July 2, 2011, and 2,036 on July 3, 2010. Since we can have significant fluctuations in product demand, we seek to maintain +flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 28, 2012 our order backlog was valued at approximately $83.1 million, +compared to approximately $54.9 million on July 30, 2011. Even though our order backlog is comprised of firm purchase orders, the amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future +sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we +will attempt to negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due +to design modifications, customer forecast changes, or other customer requirements. +5 +Table of Contents +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 11, “Enterprise-Wide Disclosures” of the consolidated financial +statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +53 +President and Chief Executive Officer +Ronald F. Klawitter +60 +Executive Vice President of Administration, Chief Financial Officer and Treasurer +Douglas G. Burkhardt +54 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +50 +Executive Vice President of Business Development +Lawrence J. Bostwick +60 +Vice President of Engineering and Quality +Brett R. Larsen +39 +Vice President of Finance and Controller +Frank Crispigna III +51 +Vice President of Materials +Duane D. Mackleit +44 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age +53, has been President and Chief Executive officer of the Company since April 2009. Previously he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and +Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held +various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of +Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +RONALD F. +KLAWITTER – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Klawitter, age 60, has been +Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary, and Treasurer of the Company from October 1995 to July 1997. He was Acting Secretary from November 1994 to +October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President of Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. Mr. Klawitter has a BA +degree from Wittenberg University and is a Certified Public Accountant. +6 +Table of Contents +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 54, has been Executive Vice President of Worldwide Operations of the Company since July 22, 2010. Previously +Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China +Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, +Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 +years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 50, has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice +President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to +July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From +1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. +Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 60, has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate +Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He +is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. +Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +BRETT R. LARSEN – Vice President of Finance, and Controller +Mr. Larsen, age 39, has served as Vice President of Finance and Controller since February 2010. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From +October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, +Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting +and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +FRANK CRISPIGNA III – Vice +President of Materials +Mr. Crispigna, age 51, has been Vice President of Materials of the company since October 2011. Prior to this, +Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and +a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 44, has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July +2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key +Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +7 +Table of Contents +Available Information +Our principal executive offices are located at N. 4424 Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at +http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information +presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described +below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND +UNCERTAINTIES THAT COULD AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause +results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects”, “believes”, “anticipates” and similar expressions are intended to identify +forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and +global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our +competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers that supply the education, +consumer products, and gambling industries, could affect future quarterly results. Additionally, our customers could be impacted by the illiquidity of the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our +customers may request accelerated production that can stress resources and reduce operating margins. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating +results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new +customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates +and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, impairment of +long-lived assets, long-term incentive compensation accrual, and the provision for warranty costs. +We are exposed to general economic +conditions, which could have a material adverse impact on our business, operating results and financial condition. +Recently there have +been adverse conditions and uncertainty in the global economy as the result of unstable global financial and credit markets, inflation, and recession. These unfavorable economic conditions and the weakness of the credit market could affect the +demand for our customers’ products. The current global macroeconomic environment may affect some of our customers that could reduce orders and change forecasts which could adversely affect our sales in future periods. Additionally, the +financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +8 +Table of Contents +The Company’s ability to secure and maintain sufficient credit arrangements is key to its +continued operations . +There is no assurance that the Company will be able to retain or renew its credit agreements in the future. In +the event the business grows rapidly or the uncertain macroeconomic climate continues, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that the Company will be able to obtain equity or +debt financing at acceptable terms, or at all in the future. For a summary of the Company’s banking arrangements, see Note 4, Long-Term Debt, of the “Notes to Consolidated Financial Statements” in this Annual Report on Form 10-K. +We depend on a limited number of suppliers for components that are critical to our manufacturing processes. A shortage of these +components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ +products. We have seen supply shortages in certain electronic components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components +outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to +our customers which could adversely affect our operating results and damage customer relationships. +Cash and cash equivalents are +exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in +excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the +insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +We operate in a highly competitive +industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may +offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial +condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have +invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will +continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, +however, require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our +business, operating results and financial condition. Specifically, some of our major customers provide products to the banking and gambling industries which have been adversely affected by the unfavorable economic environment. The contraction in +demand from our customers in these industries could continue to impact our customer orders and continue to have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent +or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +Table of Contents +Our international operations may be subject to certain risks. +Most of the products we manufacture are in facilities located in Mexico and China. These international operations may be subject to a number of risks, +including: +• +difficulties in staffing and managing foreign operations; +• +political and economic instability (including acts of terrorism, civil unrest, forms of violence and outbreaks of war), which could impact our ability +to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +fluctuations in currency exchange rates, which could affect component costs, local payroll, utility and other expenses; +• +inability to utilize net operating losses generated by our foreign operations to reduce our U.S. income taxes; and +• +our foreign locations may be impacted by hurricanes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and +other natural or manmade disasters. +Our operations in certain foreign locations receive favorable income tax treatment in +the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate +fluctuations among other currencies used by us could directly or indirectly affect our financial results. Future currency fluctuations are dependent upon a number of factors and cannot be easily predicted. We currently use Mexican peso forward +contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. However, unexpected losses could occur from future fluctuations in exchange rates. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in +foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue +to attract and retain qualified employees. There can be no assurance that we will be successful in attracting and retaining such personnel. The loss of key employees could have a material adverse effect on our business, operating results and +financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be +adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry +standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will +depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving +and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing +and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +10 +Table of Contents +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our +operating results and such costs may not be recoverable if such new programs or transferred programs are cancelled. +Start-up costs, +the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. +These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these +factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace +anticipated new program revenues. +An adverse change in the interest rates for our borrowings could adversely affect our financial +condition. +We are exposed to interest rate risk under our revolving line of credit with interest rates based on various levels of +margin added to published prime rate and LIBOR rates depending on the calculation of a certain financial covenant. +Compliance or the +failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a +variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future +liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant +expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price +may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as variations in quarterly operating results or changes in earnings estimates, or to +factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific +companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal +controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance +that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments +in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to +error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing rapid growth which can place considerable additional demands upon our management team and our +operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business +relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material +adverse effect on our results of operations. +11 +Table of Contents +If our manufacturing processes and services do not comply with applicable statutory and regulatory +requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory +requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this +agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our +manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or +error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or cancelled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure +of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur +considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the +defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain +components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about +the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and +customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend +on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, +floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, +break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the +event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation, even where a claim is without merit, could result in substantial costs and diversion of resources. +Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +12 +Table of Contents +Item 1B. +UNRESOLVED STAFF COMMENTS +None +Item 2. +PROPERTIES +We +have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/ +Owned) +Description of Use +Spokane Valley, Washington (1) +75,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +191,000 +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (2) +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (3) +— +Leased +Manufacturing and warehouse +Juarez, Mexico (4) +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (5) +105,000 +Leased +Warehouse +Total Mexico +623,000 +Shanghai, China (6) +95,000 +Leased +Manufacturing +Shanghai, China (7) +36,000 +Leased +Manufacturing +Total China +131,000 +Grand Total +945,000 +(1) +On June 15, 2010, the company amended its lease with Royal Hills Associates (RHA) to extend the lease for an additional ten years, which we +continue to occupy as our headquarters. Subsequent to June 30, 2012, we added an additional 13,000 square feet to extend our manufacturing and warehouse space. +(2) +During fiscal year 2010, we purchased a 115,000 square foot manufacturing facility in Juarez, Mexico for additional assembly space. +(3) +In fiscal year 2009, we leased a 72,000 square feet facility in Juarez, Mexico for more storage capacity and additional assembly space. This lease +expired August 30, 2012. +(4) +During fiscal year 2012, we purchased an additional 103,000 square feet of manufacturing and warehouse space. +(5) +During fiscal year 2012, we entered into an agreement to lease an additional 105,000 square feet of warehouse space to replace the 72,000 square feet +leased space that expired August 30, 2012. +(6) +During fiscal year 2011, we amended the lease of our China facility whereby extending the term to December 2015 and increasing our leased space to +95,000 square feet to accommodate an additional SMT line and for additional assembly space. +(7) +During fiscal year 2011, we entered into an agreement to lease an additional 36,000 square feet of manufacturing space. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional +benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into +additional manufacturing and warehouse space. +13 +Table of Contents +All of our facilities are ISO certified to ISO 9001:2008 standards, ISO-14001 environmental standards, +ISO-13485:2003 medical devices standards, AS9100C aviation, space and defense standards, ISO/TS 16949 automotive standards and to Customs Trade Partnership against Terrorism (CTPAT). The Spokane, Washington facilities are additionally registered by +the US State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the +aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC”. Quarterly high and low sales prices for our common stock for fiscal +years 2012 and 2011 were as follows: +2012 +2011 +High +Low +High +Low +First Quarter +$ +4.70 +$ +3.21 +$ +6.17 +$ +4.60 +Second Quarter +5.08 +3.22 +6.84 +5.01 +Third Quarter +11.49 +4.71 +6.11 +4.31 +Fourth Quarter +13.16 +7.60 +5.50 +4.05 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations +represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of +June 30, 2012, we had 762 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo, N.A. we are restricted from declaring or paying dividends in cash or stock. We have not paid a cash dividend and do not +anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual +Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +14 +Table of Contents +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the +NASDAQ Electronic Components Index in fiscal 2012. +6/30/07 +6/28/08 +6/27/09 +7/3/10 +7/2/11 +6/30/12 +Key Tronic Corporation +100.00 +69.55 +32.42 +95.87 +88.80 +161.89 +NASDAQ Composite +100.00 +84.54 +73.03 +82.88 +110.33 +115.30 +NASDAQ Electronic Components +100.00 +89.07 +65.96 +78.95 +100.22 +84.78 +15 +Table of Contents +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and +Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, +except for Supplemental Data and Per Share Amounts) +Fiscal Years +June 30, 2012 +July 2, 2011 +July 3, 2010 +June 27, 2009 +June 28, 2008 +Consolidated Statements of Operations Data : +Net sales +$ +346,475 +$ +253,846 +$ +199,620 +$ +184,924 +$ +204,122 +Gross profit +29,836 +20,648 +19,250 +13,180 +16,820 +Gross margin percentage +8.6 +% +8.1 +% +9.6 +% +7.1 +% +8.2 +% +Operating income +14,351 +6,939 +7,388 +1,783 +6,834 +Operating margin percentage +4.1 +% +2.7 +% +3.7 +% +1.0 +% +3.3 +% +Net income +11,626 +5,736 +8,690 +1,063 +5,584 +Earnings per share – diluted +1.10 +0.55 +0.85 +0.11 +0.54 +Consolidated Cash Flow Data : +Cash flows (used in) provided by operations +(5,066 +) +(2,569 +) +3,534 +10,038 +(718 +) +Capital expenditures +4,654 +3,818 +3,378 +1,891 +1,180 +Consolidated Balance Sheet Data : +Net working capital (1) +76,236 +58,307 +44,708 +37,444 +45,695 +Total assets +150,912 +112,364 +101,642 +77,755 +98,344 +Long-term liabilities +19,050 +11,063 +4,236 +3,030 +13,241 +Shareholders’ equity +78,608 +68,023 +59,417 +51,114 +49,081 +Book value per share (2) +$ +7.50 +$ +6.54 +$ +5.79 +$ +5.08 +$ +4.90 +Supplemental Data : +Number of shares outstanding at year-end +10,481,356 +10,399,187 +10,264,390 +10,065,974 +10,024,308 +Number of employees at year-end +2,700 +1,997 +2,036 +1,963 +2,502 +Approximate square footage of operational facilities +945,000 +796,000 +987,000 +849,000 +777,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that +are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +16 +Table of Contents +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in +electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly +services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product +fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity and logistical advantages to continue to win new business. The following information should be read in conjunction with the +consolidated financial statements included herein and with Item 1A, Risk Factors. +Our mission is to provide our customers with superior +manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During fiscal year +2012 we set a new record for annual revenue of $346.5 million, a 36.5 percent growth as compared to sales of $253.8 million in fiscal year 2011. The increase in net sales was primarily driven by an increase in revenues related to new programs for +both new and longstanding customers and a net increase in demand related to current customer programs, partially offset by the negative impact of the uncertain macroeconomic environment. Net sales for the first quarter of fiscal year 2013 are +expected to be within the range of $94 million to $99 million. Future results will depend on actual levels of customers’ orders, the timing of the start up of production of new product programs and the potential impact of the macroeconomic +uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +The concentration of our largest customers increased during fiscal year 2012 with the top five customers’ sales increasing to 73 percent of total sales in 2012 from 62 percent in 2011, and 57 percent +in 2010. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, +military supplies, computer accessories, electronic whiteboards, medical, educational, irrigations, automotive, transportation management and robotics. The growth during fiscal year 2012 was powered by an increasingly diverse mix of new customer +programs. At the end of fiscal year 2012, we were generating revenue from 165 separate programs and 48 distinct customers as compared to 119 programs and 33 customers at the end of fiscal year 2011. These new customers have programs that represent +small annual sales while others have multi-million-dollar potential. +Gross profit as a percent of sales was 8.6 percent in fiscal year 2012 +compared to 8.1 percent for the prior fiscal year. This 0.5 percentage point increase in gross profit as a percentage of net sales during fiscal year 2012 as compared to fiscal year 2011 is primarily related to a 2.3 percentage point improvement in +leveraging of certain overhead costs, as a percent of sales, partially offset by a 1.8 percentage point increase in material costs, as a percent of sales, resulting from higher material content in certain new customer programs. The level of gross +margin is impacted by product mix, timing of the start up of new programs, facility utilization, pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter. +Operating income as a percentage of sales for fiscal year 2012 was 4.1 percent compared to 2.7 percent for fiscal year 2011. The increase in operating +income as a percentage of sales was due to an increase in gross margin, leveraging of certain operating expenses and by improving efficiencies during fiscal year 2012. +Net income for fiscal year 2012 was $11.6 million or $1.10 per diluted share, as compared to net income of $5.7 million or $0.55 per diluted share for fiscal year 2011. The increase in net income for +fiscal year 2012 as compared to fiscal year 2011 was primarily due to the increase in net sales coupled with an improvement in our gross margin and operating income partially offset by an increase in income tax expense. +17 +Table of Contents +We maintain a strong balance sheet with a current ratio of 2.4 and a long-term debt to equity ratio of 0.19. +Total cash used in operating activities as defined on our cash flow statement was $5.1 million during fiscal year 2012. However, we maintain sufficient liquidity for our expected future operations and had $15.0 million in outstanding borrowings on +our revolving line of credit with Wells Fargo, N.A. and $15.0 million remained available at June 30, 2012. We believe cash flow from operations, our borrowing capacity, and equipment lease financing should provide adequate capital for planned +growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 30, 2012 with the Fiscal Year Ended July 2, 2011 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below +should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 30, +2012 +% of +net sales +July 2, +2011 +% of +net sales +$ change +% +point +change +Net sales +$ +346,475 +100.0 +% +$ +253,846 +100.0 +% +$ +92,629 +— +% +Cost of sales +316,639 +91.4 +233,198 +91.9 +83,441 +(0.5 +) +Gross profit +29,836 +8.6 +20,648 +8.1 +9,188 +0.5 +Operating expenses: +Research, development and engineering +4,444 +1.3 +3,782 +1.5 +662 +(0.2 +) +Selling, general and administrative +11,041 +3.2 +9,927 +3.9 +1,114 +(0.7 +) +Total operating expenses +15,485 +4.5 +13,709 +5.4 +1,776 +(0.9 +) +Operating income +14,351 +4.1 +6,939 +2.7 +7,412 +1.4 +Interest expense, net +510 +0.1 +457 +0.2 +53 +(0.1 +) +Income before income taxes +13,841 +4.0 +6,482 +2.6 +7,359 +1.4 +Income tax provision +2,215 +0.6 +746 +0.3 +1,469 +0.3 +Net income +$ +11,626 +3.4 +% +$ +5,736 +2.3 +% +$ +5,890 +1.1 +% +Effective income tax rate +16.0 +% +11.5 +% +Net Sales +Net sales were $346.5 million and $253.8 million in fiscal years 2012 and 2011, respectively. +Net sales increased $92.6 million during fiscal year 2012 as compared with fiscal year 2011. This increase in net sales was primarily driven by an +approximate $90.6 million increase in revenues related to new programs for both new and longstanding customers and to a lesser extent a $2.9 million increase related to increased demand from certain current customer programs. These increases were +partially offset by $0.9 million related to customer program losses. The negative impact resulting from the uncertain macroeconomic environment is reflected in the analysis of our new and longstanding customers programs as discussed above. +18 +Table of Contents +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2012 +and 2011: +Years Ended +June 30, 2012 +July 2, 2011 +Communication +36 +% +22 +% +Consumer +20 +20 +Gaming +18 +16 +Transaction Printer +12 +18 +Computer and Peripheral +7 +13 +Industrial +6 +6 +Commercial Printer +1 +5 +Total +100 +% +100 +% +We provide services to customers in a number of industries and produce a variety of products for our customers in each +industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 40.6 percent, and 31.9 percent of our total net sales in fiscal years 2012, and 2011, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 91.4 percent, +and 91.9 percent in fiscal years 2012, and 2011, respectively. +Total cost of materials as a percentage of net sales was approximately 70.4 +percent, and 68.6 percent in fiscal years 2012, and 2011, respectively. The change from year-to-year is primarily the result of higher material content in certain new customer programs and changes in product mix. +Production and support costs as a percentage of net sales were 21.0 percent, and 23.3 percent in fiscal years 2012, and 2011, respectively. The decrease +in fiscal year 2012 is primarily related to the leveraging of our fixed costs as a percentage of sales during the fiscal year. +We provide for +obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.8 million, and $0.3 million in fiscal years 2012, +and 2011, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and +anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $65,000 +and $158,000 in fiscal years 2012, and 2011, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.6 percent, and 8.1 percent in fiscal years 2012, and 2011, respectively. +The 0.5 percentage point increase in gross profit as a percentage of net sales during fiscal year 2012 as compared to fiscal year 2011 is primarily +related to a 2.3 percentage point improvement in leveraging of certain overhead costs, as a percent of sales, partially offset by a 1.8 percentage point increase in material costs, as a percent of sales, resulting from higher material content in +certain new customer programs and changes in product mix. +We took early pay discounts to suppliers that totaled approximately $932,000 and +$678,000, in fiscal years 2012, and 2011, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +19 +Table of Contents +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to +period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for +customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in +future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information +technology and facilities costs. Total RD&E expense was $4.4 million and $3.8 million in fiscal years 2012, and 2011, respectively. This $0.6 million increase is primarily the result of increased headcount and to a lesser extent higher incentive +compensation. +Total RD&E expenses as a percent of net sales were 1.3 percent and 1.5 percent in fiscal years 2012, and 2011, +respectively. This 0.2 percentage point improvement in RD&E is primarily related to our continued success in leveraging operating expenses as a percent of net sales. +Selling, General and Administrative +Selling, general and administrative expenses +(SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $11.0 million +and $9.9 million in fiscal years 2012, and 2011, respectively. This $1.1 million increase is primarily related to an increase in headcount. +Total SG&A expenses as a percent of net sales were 3.2 percent, and 3.9 percent in fiscal years 2012, and 2011, respectively. This 0.7 percentage +point improvement in SG&A is primarily related to our continued success in leveraging operating expenses as a percent of net sales. +Interest Expense +We had net +interest expense of $0.5 million, and $0.5 million in fiscal years 2012, and 2011, respectively. Interest expense for fiscal year 2012 remained relatively flat as compared to fiscal year 2011. +Income Tax Provision +We had an +income tax expense of $2.2 million during fiscal year 2012 as compared to an income tax expense of $746,000 in fiscal year 2011. The income tax expense recognized during fiscal 2012 was primarily a function of U.S. and foreign taxes recognized at +the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. The income tax expense recognized during fiscal 2011 was primarily a function of U.S. and +foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits, the release of the valuation allowance in China, and changes in potential foreign tax credits. +Due to increased profitability, revenue growth, and new customer programs, we utilized all remaining domestic net operating loss carryforwards (NOLs) +during fiscal year 2012. Furthermore, all previous NOL carryforwards in China have been fully utilized as well. As a result, there is no remaining deferred tax asset as of June 30, 2012 related to NOLs. In addition, we reviewed our requirements +for liquidity domestically to fund our revenue growth and to look for potential future acquisitions. We continue to anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential foreign tax credits were +first included in the income tax benefit that was realized during fiscal year 2010 and certain changes in the estimates of foreign earnings and profits and tax pools resulted in the recognition of additional tax benefits during fiscal years 2011 and +2012. For further information on taxes please review footnote 5 of the “Notes to Consolidated Financial Statements”. +20 +Table of Contents +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, +product manufacturing, and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns an SMT, assembly and molding facility, and five assembly and storage facilities in Juarez, Mexico. This subsidiary is +primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly and warehouse capabilities in Shanghai, China, which +began operations in 1999. Its primary function is to provide EMS services for export; however, it is also currently manufacturing certain electronic keyboards. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $140.8 million and $81.1 million in fiscal years 2012, and 2011, respectively. Products and +manufacturing services provided by our subsidiary operations are primarily sold to customers directly by the parent company. Key Tronic Computer Peripherals (Shanghai) Co., Ltd., our subsidiary in Shanghai, China, had only minimal direct sales to +customers in China during the past two fiscal years. +Comparison of the Fiscal Year Ended July 2, 2011 with the Fiscal Year +Ended July 3, 2010 +The following table sets forth for the periods indicated certain items of the consolidated statements of +income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 2, +2011 +% of +net sales +July 3, +2010 +% of +net sales +$ change +% +point +change +Net sales +$ +253,846 +100.0 +% +$ +199,620 +100.0 +% +$ +54,226 +— +% +Cost of sales +233,198 +91.9 +180,370 +90.4 +52,828 +1.5 +Gross profit +20,648 +8.1 +19,250 +9.6 +1,398 +(1.5 +) +Operating expenses: +Research, development and engineering +3,782 +1.5 +2,783 +1.4 +999 +0.1 +Selling, general and administrative +9,927 +3.9 +9,079 +4.5 +848 +(0.6 +) +Total operating expenses +13,709 +5.4 +11,862 +5.9 +1,847 +(0.5 +) +Operating income +6,939 +2.7 +7,388 +3.7 +(449 +) +(1.0 +) +Interest expense, net +457 +0.2 +102 +0.1 +355 +0.1 +Income before income taxes +6,482 +2.6 +7,286 +3.6 +(804 +) +(1.0 +) +Income tax provision (benefit) +746 +0.3 +(1,404 +) +0.7 +(2,150 +) +(0.4 +) +Net income +$ +5,736 +2.3 +% +$ +8,690 +4.4 +% +$ +(2,954 +) +(2.1 +)% +Effective income tax rate +11.5 +% +(19.3 +)% +Net Sales +Net sales were $253.8 million, and $199.6 million in fiscal years 2011 and 2010, respectively. +Net sales increased $54.2 million during fiscal year 2011 as compared with fiscal year 2010. This increase in net sales was primarily driven by an +approximate $77.9 million increase in revenues related to new programs for both new and longstanding customers. This was partially offset by a $18.5 million decline related to decreased demand from certain current customer programs. In addition, +during fiscal year 2011 we experienced an approximately $5.2 million decline related to the negative impact of end-of-life customer programs and to a lesser extent customer program losses. The negative impact resulting from industry-wide shortages +in the global supply chain that occurred throughout most of the year and the uncertain macroeconomic environment are reflected in the analysis of our new and longstanding customers programs as discussed above. +21 +Table of Contents +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2011 +and 2010: +Years Ended +July 2, 2011 +July 3, 2010 +Communication +22 +% +11 +% +Consumer +20 +26 +Gaming +16 +13 +Transaction Printer +18 +22 +Computer and Peripheral +13 +15 +Industrial +6 +4 +Commercial Printer +5 +9 +Total +100 +% +100 +% +We provide services to customers in a number of industries and produce a variety of products for our customers in each +industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 31.9 percent, and 17.9 percent of our total net sales in fiscal years 2011, and 2010, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 91.9 percent, +and 90.4 percent in fiscal years 2011, and 2010, respectively. +Total cost of materials as a percentage of net sales was approximately 68.6 +percent, and 62.2 percent in fiscal years 2011, and 2010, respectively. The change from year-to-year is primarily the result of higher material content in certain new customer programs and changes in product mix. +Production and support costs as a percentage of net sales were 23.3 percent, and 28.2 percent in fiscal years 2011, and 2010, respectively. The decrease +in fiscal year 2011 is primarily related to the leveraging of our fixed costs as a percentage of sales during the fiscal year. +We provide for +obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.3 million, and $2.2 million in fiscal years 2011, +and 2010, respectively. The large provision in fiscal year 2010 was primarily due to a discontinuance of manufacturing for certain customers that became no longer viable. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards +and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $158,000 and $45,000 in fiscal years 2011, and 2010, respectively. +Gross Profit +Gross profit as a +percentage of net sales was 8.1 percent, and 9.6 percent in fiscal years 2011, and 2010, respectively. +The 1.5 percentage point decrease in +gross profit as a percentage of net sales during fiscal year 2011 as compared to fiscal year 2010 is primarily related to a 6.4 percentage point increase in material costs, as a percent of sales, resulting from higher material content in certain new +customer programs, partially offset by a 4.9 percentage point improvement in leveraging of certain overhead costs. +22 +Table of Contents +We took early pay discounts to suppliers that totaled approximately $678,000, and $364,000, in fiscal years +2011, and 2010, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product +life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the +EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering +expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E was $3.8 million, and $2.8 million in fiscal +years 2011, and 2010, respectively. As a percentage of net sales, RD&E was 1.5 percent and 1.4 percent in fiscal years 2011, and 2010, respectively. The increase in RD&E in fiscal year 2011 is primarily the result of increased headcount and +to a lesser extent higher incentive compensation. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales +commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $9.9 million, and $9.1 million in fiscal years 2011, and 2010, respectively. As a percentage of net sales +SG&A was 3.9 percent, and 4.5 percent in fiscal years 2011, and 2010, respectively. Approximately half of our SG&A expenses relates to salary costs of our employees. +The $0.8 million increase in SG&A expenses in fiscal year 2011 as compared to fiscal year 2010 is primarily due to a $0.5 million increase in outside services and professional fees, a $0.4 million +increase in salary related costs, and a $0.3 million increase related to other overhead costs. This was partially offset by an approximate $0.4 million decrease in incentive compensation expense. +Interest Expense +We had net +interest expense of $0.5 million, and $0.1 million in fiscal years 2011, and 2010, respectively. Interest expense increased in fiscal year 2011 when compared to fiscal year 2010 as the average balance of the revolving line of credit was higher in +addition to interest expense incurred as a result of our capital lease obligations. We often utilize short-term fixed LIBOR rates on portions of our revolving line of credit to limit the affect of interest rate volatilities. +Income Tax Provision +We had an +income tax expense of $746,000 during fiscal year 2011 as compared to an income tax benefit of $1.4 million in fiscal year 2010. The income tax expense recognized during fiscal 2011 was primarily a function of U.S. and foreign taxes recognized at +the statutory rates offset by the net benefit associated with federal research and development tax credits, the release of the valuation allowance in China, and changes in potential foreign tax credits. The income tax benefit of fiscal year 2010 is +primarily related to the release of the valuation allowance on our deferred tax assets related to domestic NOLs and foreign tax credits, partially offset by the recognition of domestic deferred tax liabilities for an unremitted portion of foreign +earnings and the change of applicable tax regimes in Mexico. +Due to increased profitability, revenue growth, and new customer programs, we +determined that a valuation allowance against our domestic NOLs is not required. We anticipated that we would fully utilize our domestic NOLs prior to their expiration. In addition, we reviewed our requirements for liquidity domestically to fund our +revenue growth and to look for potential future acquisitions. We have changed our previous assessments of being permanently reinvested and now anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential +foreign tax credits were first included in the income tax benefit that was realized during fiscal year 2010 and certain changes in the estimates of foreign earnings and profits and tax pools resulted in the recognition of additional tax benefits +during fiscal year 2011. For further information on taxes please review footnote 5 of the “Notes to Consolidated Financial Statements”. +23 +Table of Contents +International Subsidiaries +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $81.1 million, and $35.7 million in fiscal years 2011, and 2010, respectively. Products and +manufacturing services provided by our subsidiary operations are primarily sold to customers directly by the parent company. Key Tronic Computer Peripherals (Shanghai) Co., Ltd., our subsidiary in Shanghai, China, had only minimal direct sales to +customers in China during the past two fiscal years. +Capital Resources and Liquidity +Operating Cash Flow +Net cash used in +operating activities for fiscal years 2012 and 2011 were $5.1 million and $2.6 million compared to net cash provided by operating activities of $3.5 million in fiscal year 2010. +This $2.5 million year-over-year change is primarily due to an increase in trade receivables and inventory, partially offset by an increase in accounts payable. Trade receivables increased by $20.3 +million as a result of the increase in sales that occurred during fiscal year 2012. The $17.6 million increase in inventory was attributable to our recent and expected growth in production levels for a number of new programs. The $16.9 million +increase in accounts payable was primarily driven by the timing of payments and terms of the supply chain related to new programs. +This $6.1 +million year-over-year change from fiscal year 2011 and 2010 was primarily due to an increase in trade receivables and inventory, and a decrease in accounts payable. Trade receivables increased by $5.7 million as a result of the increase in sales +that occurred during the fourth quarter of fiscal year 2011. The $2.1 million increase in inventory was attributable to our recent and expected growth in production levels for a number of new programs. The $3.0 million decrease in accounts payable +was primarily driven by the timing of payments and terms of the supply chain related to new programs. +We purchase inventory based on customer +forecasts, orders and expected lead times. When those forecasts cannot be met or changes are made to lead times, inventory can increase. Accounts payable fluctuates with changes in inventory levels, volume of purchases, and negotiated supplier +terms. +Investing Cash Flow +Cash flows used in investing activities were $4.6 million, $3.7 million, and $3.3 million in fiscal years 2012, 2011 and 2010, respectively. Cash used in +investing activities is for capital expenditures partially offset by proceeds from the sale of property and equipment. Capital expenditures were $4.7 million, $3.8 million, and $3.4 million in fiscal years 2012, 2011, and 2010, respectively. Our +capital expenditures are primarily for purchases of manufacturing assets to support our operations in the United States, Mexico and China. The increase in capital expenditures for fiscal year 2012 as compared to fiscal year 2011 was primarily +related to the purchase of a manufacturing facility and to a lesser extent the increased investment in manufacturing equipment to support the requirements of our growing customer programs and sales. The increase in capital expenditures for fiscal +year 2011 as compared to fiscal year 2010 is primarily related to the increased investment in manufacturing equipment to support the requirements of our growing customer programs and sales. +Financing Cash Flow +Cash flows provided by financing activities were $9.0 million in +fiscal year 2012 as compared to cash flows provided by financing activities of $6.7 million and cash used in financing activities of $0.2 million in fiscal years 2011 and 2010, respectively. Our primary financing activity in fiscal years 2012, 2011, +and 2010 was borrowing and repayment under our revolving line of our credit facility. Our credit agreement with Wells Fargo Bank, N.A. provides a revolving line of credit facility of up to $30 million. The agreement specifies that the proceeds +of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. The outstanding balance under the credit facility was $15.0 million as of June 30, 2012. We had +availability to borrow an additional $15.0 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. During fiscal year 2012, cash provided by financing activities reflected payments of $0.7 million on capital +leases. +24 +Table of Contents +Our cash requirements are affected by the level of current operations and new EMS programs. We believe +that projected cash from operations, funds available under the revolving credit facility and leasing capabilities will be sufficient to meet our working and fixed capital requirements for the foreseeable future. As of June 30, 2012, we had +approximately $0.5 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company could be subject to additional income taxes payable in the U.S. The total amount of additional +tax required for the amount of foreign subsidiary cash on hand as of June 30, 2012 would approximate $28,000. +Contractual Obligations +and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table +below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2013 +2014 +2015 +2016 +2017 +Thereafter +Wells Fargo Bank N.A. revolving loan (1) +$ +15,000 +$ +— +$ +— +$ +— +$ +— +$ +15,000 +$ +— +Operating leases (2) +8,281 +1,461 +1,478 +1,423 +976 +722 +2,221 +Capital leases (3) +1,370 +782 +588 +— +— +— +— +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt”. As +of June 30, 2012, we were in compliance with our loan covenants. Breaching these covenants could have resulted in a material impact on our operations or financial condition. +(2) +We maintain vertically integrated manufacturing operations in Mexico and China. Such operations are heavily dependent upon technically superior +manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. In addition, we lease some +of our administrative and manufacturing facilities. A complete discussion of properties can be found in Part 1, Item 2 at “Properties”. Leases have proven to be an acceptable method for us to acquire new or replacement equipment and +to maintain facilities with a minimum impact on our short term cash flows for operations. Subsequent to June 30, 2012, the Company entered into an additional lease of approximately 13,000 square feet at a rate of $8.00 per square foot per year +with the lease terminating on February 28, 2016. +(3) +During fiscal year 2011, we entered into capital leases for the purchase of certain equipment and leasehold improvements. See Note 8, “Commitments +and Contingencies” for additional discussion of capital lease obligations. Amounts presented above include interest and principal, if applicable. +(4) +As of June 30, 2012, we had open purchase order commitments for materials and other supplies of approximately $171.3 million. Included in the open +purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels. In addition, we have contracts with our customers that minimize our exposure to losses for +material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on +the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the +cash requirements presented above, we have various other accruals which are not included in the table above. We owe our suppliers approximately $36.4 million for accounts payable and shipments in transit at the end of the fiscal year. We generally +pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +25 +Table of Contents +We believe that cash flows generated from operations, leasing facilities, and funds available under the +revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +Critical +Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and +assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial +statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently +uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Inactive, Obsolete, and Surplus Inventory Reserve +We reserve for inventories that we deem +inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we +would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time +assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase +material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, +obsolete or surplus inventory against earnings. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 30, 2012, we deemed no allowance was necessary. The allowance +for doubtful accounts was $111,000 as of July 2, 2011. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of +potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial +problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense +recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. As we have made the transition from manufacturing primarily keyboards to primarily EMS +products, our exposure to warranty claims has declined significantly. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects +for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and the provision for U.S. taxes on undistributed earnings of foreign subsidiaries not deemed to be permanently invested. We do not record +tax liabilities on undistributed earnings of international subsidiaries that are permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary +differences is reported as deferred income taxes. The deferred income taxes are classified as current or long-term based on the classification of the related asset or liability. The most significant areas involving management judgments include +deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable +income which may change. +26 +Table of Contents +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 +requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant +date based upon the value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based +awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, +option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and +have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical +volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical +exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or +expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our +stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience +of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent +the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate +that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by +the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +27 +Table of Contents +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted +transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a +derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income”, until earnings are affected by the variability of cash flows. See Note 10 of the Company’s consolidated financial statements for +additional information. +Accounting Pronouncements +See Note 1 to our consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal +course of business. Our major market risk relates to our secured debt. Our revolving credit facility is secured by substantially all of our assets. The interest rates applicable to our revolving credit facility fluctuate with the JP Morgan Chase +Bank prime rate and LIBOR rates. There was $15.0 million in outstanding borrowings under our revolving credit facility as of June 30, 2012, and the interest rate being paid on the outstanding balance was in the range of 2.35% – 3.25%. See +“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional +information regarding our revolving credit facility. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate +fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. +There was $57.8 million of foreign currency forward contracts outstanding as of June 30, 2012. The fair value of these contracts was approximately ($1.0) million. See Note 10 – “Derivative Financial Instruments” to the +Consolidated Financial Statements for additional information regarding our derivative instruments. +28 +Table of Contents +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Shareholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key +Tronic Corporation (the Company) as of June 30, 2012 and July 2, 2011 and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended +June 30, 2012. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the +Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements +are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a +basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such +opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the +overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the +consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation at June 30, 2012 and July 2, 2011, and the results of its operations and its cash flows for each +of the three years in the period ended June 30, 2012, in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the +information set forth therein. +/s/ BDO USA, LLP +Spokane, Washington +September 10, 2012 +29 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 30, 2012 +July 2, 2011 +ASSETS +Current assets: +Cash and cash equivalents +$ +502 +$ +1,232 +Trade receivables, net (allowance for doubtful accounts of $0 and $111) +60,709 +40,350 +Inventories +58,439 +41,554 +Deferred income tax asset +5,201 +3,900 +Other +4,639 +4,549 +Total current assets +129,490 +91,585 +Property, plant and equipment, net +17,306 +14,917 +Other assets: +Deferred income tax asset +2,703 +4,219 +Other, net of accumulated amortization of $82 and $93 +1,413 +1,643 +Total assets +$ +150,912 +$ +112,364 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +43,025 +$ +26,149 +Accrued compensation and vacation +6,337 +4,436 +Current portion of other long-term obligations +729 +761 +Other +3,163 +1,932 +Total current liabilities +53,254 +33,278 +Long-term liabilities: +Revolving loan +15,011 +6,000 +Deferred income tax liability +1,094 +1,542 +Other long-term obligations +2,945 +3,521 +Total long-term liabilities +19,050 +11,063 +Commitments and contingencies (Notes 4 and 8) +Shareholders’ equity: +Common stock, no par value, authorized 25,000 shares; issued and outstanding 10,481 and 10,399 shares, +respectively +42,372 +41,014 +Retained earnings +36,895 +25,269 +Accumulated other comprehensive (loss) income +(659 +) +1,740 +Total shareholders’ equity +78,608 +68,023 +Total liabilities and shareholders’ equity +$ +150,912 +$ +112,364 +See accompanying notes to consolidated financial statements. +30 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF INCOME +(In thousands) +Years Ended +June 30, 2012 +July 2, 2011 +July 3, 2010 +Net sales +$ +346,475 +$ +253,846 +$ +199,620 +Cost of sales +316,639 +233,198 +180,370 +Gross margin +29,836 +20,648 +19,250 +Operating expenses: +Research, development and engineering +4,444 +3,782 +2,783 +Selling, general and administrative +11,041 +9,927 +9,079 +Total operating expenses +15,485 +13,709 +11,862 +Operating income +14,351 +6,939 +7,388 +Interest expense, net +510 +457 +102 +Income before income taxes +13,841 +6,482 +7,286 +Income tax provision (benefit) +2,215 +746 +(1,404 +) +Net income +$ +11,626 +$ +5,736 +$ +8,690 +Earnings per share: +Earnings per common share – basic +$ +1.11 +$ +0.55 +$ +0.86 +Weighted average shares outstanding – basic +10,447 +10,344 +10,124 +Earnings per common share – diluted +$ +1.10 +$ +0.55 +$ +0.85 +Weighted average shares outstanding – diluted +10,609 +10,407 +10,191 +See accompanying notes to consolidated financial statements. +31 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands) +Years Ended +June 30, 2012 +July 2, 2011 +July 3, 2010 +Comprehensive income: +Net income +$ +11,626 +$ +5,736 +$ +8,690 +Other comprehensive income: +Unrealized (loss) gain on foreign exchange contracts, net of tax +(2,399 +) +1,982 +(1,154 +) +Comprehensive income +$ +9,227 +$ +7,718 +$ +7,536 +Other comprehensive income for fiscal years 2012, 2011, and 2010 are reflected net of tax of approximately $(1.2) million, $1.0 +million, and $(0.1) million, respectively. +See accompanying notes to consolidated financial statements. +32 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY +(In thousands) +Accumulated +Other +Common Stock +Retained +Comprehensive +Shares +Amount +Earnings +Income (Loss) +Total +Balances, June 27, 2009 +10,066 +$ +39,359 +$ +10,843 +$ +912 +$ +51,114 +Net income +— +— +8,690 +— +8,690 +Unrealized loss on foreign exchange contracts +— +— +— +(1,154 +) +(1,154 +) +Exercise of stock options +198 +604 +— +— +604 +Tax benefit from exercise of stock options +— +163 +— +— +163 +Balances, July 3, 2010 +10,264 +40,126 +19,533 +(242 +) +59,417 +Net income +— +— +5,736 +— +5,736 +Unrealized gain on foreign exchange contracts +— +— +— +1,982 +1,982 +Exercise of stock options +135 +332 +— +— +332 +Stock-based compensation +— +556 +— +— +556 +Balances, July 2, 2011 +10,399 +41,014 +25,269 +1,740 +68,023 +Net income +— +— +11,626 +— +11,626 +Unrealized loss on foreign exchange contracts +— +— +— +(2,399 +) +(2,399 +) +Exercise of stock options +82 +225 +— +— +225 +Stock-based compensation +— +624 +— +— +624 +Tax benefit from exercise of stock options +— +509 +— +— +509 +Balances, June 30, 2012 +10,481 +$ +42,372 +$ +36,895 +$ +(659 +) +$ +78,608 +See accompanying notes to consolidated financial statements. +33 +Table of Contents +KEY TRONIC CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +June 30, 2012 +Year Ended +July 2, 2011 +July 3, 2010 +Cash flows from operating activities: +Net income +$ +11,626 +$ +5,736 +$ +8,690 +Adjustments to reconcile net income to cash (used in) provided by operating activities: +Depreciation and amortization +2,333 +2,212 +1,794 +Excess tax benefit from exercise of stock options +(509 +) +— +(163 +) +Accretion of deferred gain on sale of building +— +(39) +(78 +) +Provision for obsolete inventory +762 +299 +2,182 +(Recovery of) provision for doubtful receivables +(111 +) +15 +— +Provision for (recovery of) warranty +60 +158 +(45 +) +Loss (gain) on sale of assets +5 +(6 +) +(58 +) +Share-based compensation expense +624 +500 +57 +Deferred income taxes +221 +1,036 +(2,062 +) +Changes in operating assets and liabilities: +Trade receivables +(20,268 +) +(5,748) +(10,104 +) +Inventories +(17,647 +) +(2,078 +) +(9,666 +) +Other assets +(1,732 +) +(274 +) +(1,659 +) +Accounts payable +16,876 +(3,009 +) +10,455 +Accrued compensation and vacation +1,829 +(661 +) +1,899 +Other liabilities +865 +(710 +) +2,292 +Cash (used in) provided by operating activities +(5,066 +) +(2,569 +) +3,534 +Cash flows from investing activities: +Purchase of property and equipment +(4,654 +) +(3,818 +) +(3,378 +) +Proceeds from sale of property and equipment +9 +15 +74 +Proceeds from life insurance +— +113 +— +Cash used in investing activities +(4,645 +) +(3,690 +) +(3,304 +) +Cash flows from financing activities: +Payment of financing costs +(75 +) +(50 +) +(50 +) +Proceeds from exercise of stock options +225 +332 +604 +Excess tax benefit from exercise of stock options +509 +— +163 +Proceeds from long term debt +— +2,244 +— +Principal payments on long term debt +(689 +) +(251 +) +(172 +) +Borrowing under revolving credit agreement +114,591 +98,985 +24,931 +Repayment of revolving credit agreement +(105,580 +) +(94,539 +) +(25,789 +) +Decrease in restricted cash +— +— +124 +Cash provided by (used in) financing activities +8,981 +6,721 +(189 +) +(Decrease) increase in cash and cash equivalents +(730 +) +462 +41 +Cash and cash equivalents, beginning of year +1,232 +770 +729 +Cash and cash equivalents, end of year +$ +502 +$ +1,232 +$ +770 +Supplemental cash flow information: +Interest payments +$ +443 +$ +463 +$ +85 +Income tax payments, net of refunds +$ +1,412 +$ +533 +$ +415 +See accompanying notes to consolidated financial statements. +34 +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic +Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs), and also manufactures keyboards and other input devices. The Company’s headquarters are located in +Spokane Valley, Washington with manufacturing operations in Spokane Valley; Juarez, Mexico; and Shanghai, China. +Principles of +Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in Mexico and China. +Intercompany balances and transactions have been eliminated in consolidation. +Reclassifications +As discussed in Note 5, in the first quarter fiscal year 2012 financial statements the Company reclassified certain deferred tax assets and liabilities on +its July 2, 2011 balance sheet. The reclassification was not material to the July 2, 2011 financial statements. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America +requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and +expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, impairment of long-lived assets, +medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, and the fair values of options and stock appreciation rights granted under the Company’s stock-based compensation plans. Due to +uncertainties with respect to the assumptions and estimates actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried +at cost, which approximates fair value. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be +collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several +factors including the aging of the receivables, the current business environment, and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at +the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. The Company provides an allowance for obsolete and non-saleable inventories based on specific identification of inventory against current demand +forecasts, recent usage, and customer contract requirements. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Internally +constructed molds and dies are depreciated over the expected useful lives of one to two years. Repairs and maintenance costs are expensed as incurred. +35 +Table of Contents +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the +carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy +of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plan. The Company contracted with a separate administrative service company to supervise and +administer the program and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for individual claims. In addition, if the aggregate annual claims amount to more than 125 +percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates +its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation +that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are +expensed as incurred. +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of +the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the +manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based +on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, +which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 2.1 percent, 3.3 percent, and +2.4 percent of total revenue in fiscal years 2012, 2011, and 2010, respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and +handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering +costs are expensed as incurred. +36 +Table of Contents +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences +between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that +includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence +indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% +likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not +accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to +the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 5 for further discussions. +Earnings Per Common Share +Basic +earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially +dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase +common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect +on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and +liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 30, 2012 and +July 2, 2011, reasonably approximate their fair value. Based on the borrowing rates currently available to the Company for loans with similar terms and average maturities, the fair value of long-term debt is estimated to be $15.0 million and +$6.0 million, respectively, as of June 30, 2012 and July 2, 2011. +Stock-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, +restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock –based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee +service period, which is generally the vesting period, and is included in cost of goods sold and selling, general, and administrative expenses. +37 +Table of Contents +Newly Adopted and Recent Accounting Pronouncements +In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value +Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 amends Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements (ASC 820) by: (1) clarifying that the highest-and-best-use +and valuation-premise concepts only apply to measuring the fair value of non-financial assets; (2) allowing a reporting entity to measure the fair value of the net asset or net liability position in a manner consistent with how market +participants would price the net risk position, if certain criteria are met; (3) providing a framework for considering whether a premium or discount can be applied in a fair value measurement; (4) providing that the fair value of an +instrument classified in a reporting entity’s shareholders’ equity is estimated from the perspective of a market participant that holds the identical item as an asset; and (5) expanding the qualitative and quantitative fair value +disclosure requirements. The expanded disclosures include, for Level 3 items, a description of the valuation process and a narrative description of the sensitivity of the fair value to changes in unobservable inputs and interrelationships between +those inputs if a change in those inputs would result in a significantly different fair value measurement. ASU 2011-04 also requires disclosures about the highest-and-best-use of a non-financial asset when this use differs from the asset’s +current use and the reasons for such a difference. In addition, this ASU amends Accounting Standards Codification 820, Fair Value Measurements , to require disclosures to include any transfers between Level 1 and Level 2 of the fair value +hierarchy. The adoption of the amendments of ASU 2011-04 during the third quarter of fiscal year 2012 did not have a material impact on the Company’s consolidated financial statements. +In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 requires entities to report components of comprehensive income in +either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, and the second statement would include +components of other comprehensive income. This ASU does not change the items that must be reported in other comprehensive income. These provisions are effective for fiscal years beginning after December 15, 2011 and for interim periods within +those fiscal years; however, early adoption is permitted. The adoption of the provisions of ASU 2011-05 did not have a material impact on the Company’s consolidated financial statements. +In December 2011, the FASB issued Accounting Standards Update 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other +Comprehensive Income in Accounting Standards Update 2011-05 . ASU 2011-12 defers only those changes in ASU 2011-05 that relate to the presentation of reclassification adjustments. The Board has reinstated the requirements for the presentation of +reclassifications out of accumulated other comprehensive income that were in place before the issuance of Update 2011-05. The adoption of the amendments of ASU 2011-12 did not have a material impact on the Company’s consolidated financial +statements. +In December 2011, the FASB issued Accounting Standards Update 2011-11, Disclosures about Offsetting Assets and +Liabilities . The amendments in this Update will enhance disclosures required by U.S. GAAP by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either +Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement. The amendments are effective for fiscal years beginning after January 1, 2013 and for interim periods within +those fiscal years. The amendments of ASU 2011-11 are not expected to have a material impact on the Company’s consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the +Saturday nearest June 30. As such, fiscal years 2012, 2011, and 2010, ended on June 30, 2012, July 2, 2011, and July 3, 2010, respectively. Fiscal years 2012 and 2011 were 52 week years, whereas fiscal year 2010 was a 53 +week year. +38 +Table of Contents +2. INVENTORIES +Components of inventories were as follows: +June 30, 2012 +July 2, 2011 +(in thousands) +Finished goods +$ +9,805 +$ +5,660 +Work-in-process +6,340 +4,821 +Raw materials +42,294 +31,073 +$ +58,439 +$ +41,554 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +June 30, 2012 +July 2, 2011 +(in years) +(in thousands) +Land +— +$ +2,629 +$ +2,089 +Buildings and improvements +3 to 30 +18,300 +16,855 +Equipment +1 to 10 +35,160 +34,686 +Furniture and fixtures +3 to 5 +2,378 +2,530 +58,467 +56,160 +Accumulated depreciation +(41,161 +) +(41,243 +) +$ +17,306 +$ +14,917 +4. LONG-TERM DEBT +Note Payable - Bank +On October 15, 2010, the Company entered into an amended credit agreement with Wells Fargo Bank, N.A. thereby increasing its revolving line of credit +for up to $30 million. On January 30, 2012, the Company entered into a second amendment to the credit agreement extending the term to October 15, 2016. The agreement specifies that the proceeds of the revolving line of credit be used +primarily for working capital and general corporate purposes of the Company and its subsidiaries. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate”, as elected by the Company. +The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5%, or the Federal Funds rate plus 1.5%. The fixed rate is LIBOR plus 2.1% or LIBOR plus 2.5% depending on the level of the +Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The revolving line of credit is secured by substantially all of the assets of the Company. +The Company must comply with certain financial covenants, including a cash flow leverage ratio and a trading ratio. The credit agreement requires the +Company to maintain a minimum profit threshold, limits the maximum lease expenditures and restricts the Company from declaring or paying dividends in cash or stock. The Company is in compliance with all financial covenants for all periods presented. +As of June 30, 2012, the Company had availability to borrow an additional $15.0 million under the line of credit. The outstanding +balance under the credit facility was $15.0 million as of June 30, 2012 and the interest rate being paid on the outstanding balance was in the range of 2.35% - 3.25%. The outstanding balance under the credit facility was $6.0 million as of +July 2, 2011 and the interest rate on the outstanding balances was 2.48%. +39 +Table of Contents +5. INCOME TAXES +Income tax provision (benefit) consists of the following: +Year Ended +June 30, 2012 +July 2, 2011 +July 3, 2010 +(in thousands) +Current income tax provision: +United States +$ +1,483 +$ +34 +$ +162 +Foreign +511 +242 +496 +1,994 +276 +658 +Deferred income tax (benefit) provision: +United States +(85 +) +1,250 +(3,588 +) +Foreign +306 +(780 +) +1,526 +221 +470 +(2,062 +) +Total income tax (benefit) provision +$ +2,215 +$ +746 +$ +(1,404 +) +The Company has total tax credit carryforwards of approximately $10.2 million at June 30, 2012. Included in total +tax credits carryforwards is approximately $6.8 million in research and development (R&D) tax credits. In accordance with ASC 740, Income Taxes , management assessed the Company’s estimated taxable income and determined a need for a +valuation allowance of certain tax credits related to research and development activities which are anticipated to expire in 2012. A valuation allowance of approximately $257,000 has been recognized as of June 30, 2012 related to these tax +credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be +required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s increased profitability and estimated future +repatriations from foreign subsidiaries, it has been determined that it is more likely than not that the deferred tax assets will be realized. Therefore, no additional valuation allowance has been recognized. +Management has reviewed and updated as necessary estimates of future repatriations of the undistributed earnings of its foreign subsidiaries. Based on +this analysis, management expects to repatriate a portion of the foreign undistributed earnings based on increased sales growth driving additional U.S. capital requirements, cash requirements for potential acquisitions and to potentially implement +certain tax strategies. No foreign earnings were repatriated from either foreign subsidiary during fiscal 2012. The Company currently estimates that future repatriations from foreign subsidiaries will approximate $7.5 million. As such, as earnings +are recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes estimated to be approximately $3.1 million. Both the domestic tax and estimated withholding tax have been +recorded as part of deferred taxes as of June 30, 2012. Included in tax credits is $2.6 million related to foreign tax credits that can be used to offset future domestic income tax. All other unremitted foreign earnings are expected to remain +permanently reinvested for planned fixed asset purchases in foreign locations. +The Company has not provided for U.S. income taxes or foreign +withholding taxes on approximately $7.8 million of earnings from foreign subsidiaries which are permanently reinvested outside the U.S. The unrecognized net tax provision that would be associated with these earnings would be approximately $1.0 +million. +The Company has a wholly owned foreign subsidiary in Mexico that applies certain tax credits related to production assets that +currently offset all of the income tax liabilities under general Mexican income tax law. However, the Company is subject to a Mexican business flat tax called Impuesto Empresarial a Tasa Unica (IETU). The Company anticipates that it will be taxable +under IETU for the foreseeable future based on projected assets used in its operations and anticipated future cash flows. The effect of IETU and the associated presidential decrees have been included in the effective tax rate for the year ended +June 30, 2012. +40 +Table of Contents +The Company is required to pay taxes in China on its statutory foreign profits. The Chinese subsidiary paid +approximately $275,000 in income tax for the calendar year ended December 31, 2011 after utilization of all remaining NOL carryforwards from prior years. The Company’s effective tax rate differs from the federal tax rate as follows: +Year Ended +June 30, 2012 +July 2, 2011 +July 3, 2010 +(in thousands) +Federal income tax provision at statutory rates +$ +4,706 +$ +2,205 +$ +2,477 +Foreign tax rate differences +(361 +) +(326 +) +99 +Effect of income tax credits +(2,104 +) +(1,249 +) +— +Effect of repatriation of foreign earnings, net +— +72 +2,158 +Effect of change in applied Mexican tax regime +— +— +1,526 +Other +288 +(86 +) +211 +Change in valuation allowance +(462 +) +130 +(7,875 +) +Permanent difference +148 +— +— +Income tax provision (benefit) +$ +2,215 +$ +746 +$ +(1,404 +) +The domestic and foreign components of income before income taxes were: +Year Ended +June 30, 2012 +July 2, 2011 +July 3, 2010 +(in thousands) +Domestic +$ +10,666 +$ +4,048 +$ +6,117 +Foreign +3,175 +2,434 +1,169 +Income before income taxes +$ +13,841 +$ +6,482 +$ +7,286 +Deferred income tax assets and liabilities consist of the following at: +June 30, 2012 +July 2, 2011 +(in thousands) +Deferred tax assets: +Net operating loss carryforwards +$ +— +$ +4,565 +Tax credit carryforwards, net +4,559 +3,488 +Foreign subsidiaries – future tax credits +2,600 +2,445 +Inventory +396 +224 +Accruals +3,069 +1,789 +Other +740 +503 +Deferred income tax assets +11,364 +13,014 +Valuation allowance +(257 +) +(720 +) +Deferred income tax assets, net of valuation allowance +$ +11,107 +$ +12,294 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(3,138 +) +(3,173 +) +Fixed assets +(1,157 +) +(1,542 +) +Other +(2 +) +(1,783 +) +Deferred income tax liabilities +$ +(4,297 +) +$ +(6,498 +) +Net deferred income tax assets +$ +6,810 +$ +5,796 +Balance sheet caption reported in: +Current deferred tax asset +$ +5,201 +$ +3,900 +Long-term deferred tax asset +2,703 +4,219 +Long term deferred income tax liability +(1,094 +) +(1,542 +) +Other long term obligations +— +(781 +) +Net deferred income tax asset +$ +6,810 +$ +5,796 +41 +Table of Contents +At June 30, 2012 the Company utilized all its NOLs carried forward from prior years in both the U. S. +and Chinese jurisdictions. The Company has R&D tax credits that approximate $6.8 million that have 15 or 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2013 to 2032. The Company +also has alternative minimum tax credits approximating $726,000. The alternative minimum tax credits do not expire. +Uncertain Tax +Positions +As of June 30, 2012, the Company had unrecognized tax benefits of $3.0 million. The unrecognized tax benefits relate to +certain R&D tax credits generated in 2012 and prior years. +A reconciliation of the beginning and ending amount of unrecognized tax +benefits is as follows: +Balance at July 3, 2010 +$ +— +Additions in fiscal 2011 +781 +Balance at July 2, 2011 +$ +781 +Additions in fiscal 2012 +2,222 +Balance at June 30, 2012 +$ +3,003 +The increase from the prior year is due to additional R&D credits that were recorded in 2012 as discussed above. +Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related +to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal +jurisdiction, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +The July 2, 2011 balance sheet in the accompanying financial statements includes two reclassifications that were not reflected in the July 2, 2011 Form 10-K. The reclassifications decreased the +short term deferred tax asset by approximately $0.6 million with a corresponding decrease in the current portion of the deferred tax liability. There was also a reclassification to decrease the long term portion of the deferred tax asset by +approximately $3.6 million with a corresponding decrease in the deferred tax liability. These balance sheet reclassifications related to the netting of the deferred tax accounts within the same tax jurisdiction did not impact the Company’s debt +covenants, working capital, cash flows or income statement accounts and were not material to the July 2, 2011 consolidated financial statements. +42 +Table of Contents +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares +outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation +of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the +average market price for the period: +Years Ended +(in thousands, except per share information) +June 30, 2012 +July 2, 2011 +July 3, 2010 +Net income +$ +11,626 +$ +5,736 +$ +8,690 +Weighted average shares – basic +10,447 +10,344 +10,124 +Effect of dilutive common stock options +162 +63 +67 +Weighted average shares – diluted +10,609 +10,407 +10,191 +Earnings per share – basic +$ +1.11 +$ +0.55 +$ +0.86 +Earnings per share – diluted +$ +1.10 +$ +0.55 +$ +0.85 +Antidilutive options not included in diluted earnings per share +— +541 +113 +7. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock +options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock –based or cash-based awards. Compensation cost is recognized on a +straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold and selling general and administrative expenses. Share-based compensation +is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +On July 27, 2011, the Company granted 184,666 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $4.40 and a grant date weighted average fair +market value of $2.20. On January 26, 2012, the Company granted 32,000 SARs under the 2010 Incentive Plan to certain key employees at a strike price of $6.30 and a grant date weighted average fair market value of $3.08. In addition to service +conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over +the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +The grant date fair value for the awards granted during fiscal year 2012 were estimated using the Black Scholes option valuation method with +the following weighted average assumptions on grant date: +Fiscal Year 2012 +January 26, 2012 +July 27, 2011 +Expected dividend yield +0.00 +% +0.00 +% +Risk – free interest rate +0.52 +% +1.16 +% +Expected volatility +64.90 +% +65.50 +% +Expected life +4.00 +4.00 +43 +Table of Contents +On October 21, 2010, the Company obtained shareholder approval of the 2010 Incentive Plan at the Annual +Shareholder Meeting. As a result, the Company replaced the cash-settlement feature with a net-share-settlement feature for the SARs granted during the fourth quarter of fiscal 2010. Therefore, the awards were reclassified from liability awards to +equity awards effective October 21, 2010 at a weighted average fair value of $2.89. +The fair value for the liability awards amended to +equity awards during fiscal year 2011 were estimated using the Black-Scholes option valuation model with the following weighted average assumptions as of October 21, 2010: +Fiscal Year 2011 +October 21, 2010 +Expected dividend yield +0.00 +% +Risk – free interest rate +0.73 +% +Expected volatility +68.30 +% +Expected life +3.56 +Stock-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures +estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Stock-based +compensation expense for fiscal years ended June 30, 2012, July 2, 2011 and July 3, 2010 was $0.6 million, $0.5 million and $0.1 million, respectively. +The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which differ significantly from the SARs, as traded options have no vesting restrictions and +are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair +value estimates. +The intrinsic value for options exercised in fiscal years 2012, 2011 and 2010 was $0.3 million, $0.2 million and $0.5 +million, respectively. +As of June 30, 2012, total unrecognized compensation expense related to nonvested share-based compensation +arrangements was approximately $0.8 million. This expense is expected to be recognized over a weighted-average period of 1.47 years. +The +following table summarizes option/SARs activity of all plans from July 2, 2011 through June 30, 2012: +Shares +Available +For Grant +Options/SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balance at July 2, 2011 +678,000 +668,613 +$ +240 +$ +5.29 +3.3 +Shares authorized +— +Options/SARs granted +(216,666 +) +216,666 +Options canceled and expired +— +(18,750 +) +Options exercised +— +(82,169 +) +Balance at June 30, 2012 +461,334 +784,360 +$ +2,261 +$ +5.36 +3.1 +Exercisable at June 30, 2012 +45,694 +$ +264 +$ +2.47 +1.3 +44 +Table of Contents +The following is a summary of plan activity: +Number of +Options/SARs +Weighted Average +Exercise Price +Outstanding June 27, 2009 +784,827 +$ +3.48 +Exercised during 2010 +(198,416 +) +3.05 +Canceled +(262,917 +) +3.69 +Outstanding July 3, 2010 +323,494 +3.57 +Amended to equity +522,000 +5.89 +Exercised during 2011 +(134,797 +) +3.66 +Canceled +(42,084 +) +4.85 +Outstanding, July 2, 2011 +668,613 +5.29 +Granted during 2012 +216,666 +4.68 +Exercised during 2012 +(82,169 +) +2.74 +Canceled +(18,750 +) +6.50 +Outstanding, June 30, 2012 +784,360 +$ +5.36 +Additional information regarding options outstanding as of June 30, 2012, is as follows: +Options/SARs +Outstanding +Options/SARs +Exercisable +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$1.20 – $1.80 +7,500 +0.3 +$ +1.20 +7,500 +$ +1.20 +1.81 – 2.71 +15,000 +1.3 +2.20 +15,000 +2.20 +2.73 – 4.09 +23,194 +1.5 +3.06 +23,194 +3.06 +4.10 – 6.15 +706,666 +3.2 +5.50 +— +— +6.16 – 6.30 +32,000 +4.6 +6.30 +— +— +$1.20 to $6.30 +784,360 +3.1 +$ +5.36 +45,694 +$ +2.47 +The Company also has a defined contribution plan (401(k)) available to U.S. employees who have attained age 21. The +Company contributes an amount equal to 100% of the employee’s contribution on the first 3% of the employee’s compensation and an additional 50% of the employee’s contribution on the following 2% of the employee’s compensation. +Company contributions to the plan were approximately $0.5 million, $0.5 million, and $0.4 million during fiscal years 2012, 2011, and 2010, respectively. +8. COMMITMENTS AND CONTINGENCIES +Leases : As of June 30, 2012, the Company had equipment financed through capital leases with a net book value of $1.9 +million. The related depreciation expense for fiscal year 2012 was $0.3 million. The Company has operating and capital leases for certain equipment and production facilities, which expire at various dates during the next ten years. +45 +Table of Contents +Future minimum payments under non-cancelable operating and capital leases with initial or remaining terms of +one year or more at June 30, 2012, are summarized as follows (in thousands): +Fiscal Years Ending +Operating +Leases +Capital +Leases +2013 +$ +1,461 +$ +782 +2014 +1,478 +588 +2015 +1,423 +— +2016 +976 +— +2017 +722 +— +Thereafter +2,221 +— +Total minimum lease payments +$ +8,281 +$ +1,370 +* +* +Includes $65 of interest. +On January 11, +2011, the Company entered into a capital lease agreement. The term of the capital lease agreement extends to January 2014 with monthly payments of $16,760 and a fixed interest rate of 3.86%. At June 30, 2012, the outstanding principal balance +was $386,882 under the capital lease agreement and the net book value of the equipment was $590,424. +On April 1, 2011, the Company +entered into two capital lease agreements. The term of the capital lease agreements extends to March 2014 with monthly payments of $39,445 and $8,961, with fixed interest rates of 6.21%. At June 30, 2012, the outstanding principal balances were +$747,621 and $169,853 under the capital lease agreements. The net book value at June 30, 2012 for the equipment under the capital lease agreements was $1,152,501 and $241,295, respectively. +Subsequent to June 30, 2012, the Company entered into an additional lease of approximately 13,000 square feet at a rate of $8.00 per square foot per +year with the lease terminating on February 28, 2016. +Rental expense under operating leases was approximately $1.5 million, $2.4 +million, and $3.3 million during fiscal years 2012, 2011, and 2010, respectively. +Warranty Costs : The Company provides warranties on +certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace +the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be +required in future periods. +Components of the reserve for warranty costs during fiscal years 2012, 2011, and 2010 were as follows (in +thousands): +Balance at June 27, 2009 +$ +25 +Additions +45 +Warranty costs incurred +(45 +) +Balance at July 3, 2010 +25 +Additions +158 +Warranty costs incurred +(173 +) +Balance at July 2, 2011 +10 +Additions +65 +Warranty costs incurred +(52 +) +Balance at June 30, 2012 +$ +23 +46 +Table of Contents +Warranty expense for fiscal years 2012, 2011 and 2010 is related to workmanship claims on keyboards and +certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company +does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise +by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in +certain circumstances. +9. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and +liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted +market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable +inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 30, 2012 and July 2, 2011. +The following table summarizes the Company’s financial assets and liabilities (only those required to be measured at fair value on a recurring +basis) at fair value as of June 30, 2012 and July 2, 2011 (in thousands): +June 30, 2012 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +858 +$ +— +$ +858 +Financial Liabilities: +Foreign currency forward contracts +$ +— +$ +(1,851 +) +$ +— +$ +(1,851 +) +July 2, 2011 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +2,723 +$ +— +$ +2,723 +Financial Liabilities: +Foreign currency forward contracts +$ +— +$ +(82 +) +$ +— +$ +(82 +) +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican +peso. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the +unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income, as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 30, 2012 and July 2, 2011, reasonably approximate their fair +value. The Company’s long-term debt primarily consists of a revolving line of credit. Borrowings under this revolving line of credit bear interest at the higher of Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate +(LIBOR) plus 1.5% to 2.5%, or the Federal Funds rate plus 1.5%. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk. As a result of the determinable market rate for our +revolving credit debt it is classified within Level 2 of the fair value hierarchy. The discounted cash flow of the revolving line of credit is estimated to be $15.0 million and $6.0 million, respectively, as of June 30, 2012 and July 2, +2011, which carrying value approximates the fair value. +47 +Table of Contents +10. DERIVATIVE FINANCIAL INSTRUMENTS +The Company has entered into foreign currency forward contracts and those contracts are accounted for as cash flow hedges. The +effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The +derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company transacts business in Mexico and is subject to the risk of foreign currency exchange rate fluctuations. The Company enters into foreign +currency forward contracts to manage the foreign currency fluctuations for Mexican peso denominated payroll, utility, tax, and accounts payable expenses. The foreign currency forward contracts have terms that are matched to the underlying +transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +As of +June 30, 2012, the Company had outstanding foreign currency forward contracts of $57.8 million. These contract maturity dates extend through March 2015. As of June 30, 2012, the net amount of existing losses expected to be reclassified +into earnings within the next 12 months is $0.3 million. During the fiscal year ended June 30, 2012, the Company entered into $41.1 million of foreign currency forward contracts, which includes $5.6 million of foreign cross currency swaps which +are also accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging, and settled $21.2 million of such contracts. During the fiscal year ended July 2, 2011, the Company entered into $21.7 million of foreign +currency forward contracts and settled $14.6 million of such contracts. During the fiscal year ended July 3, 2010, the Company entered into $30.9 million of foreign currency forward contracts and settled $17.8 million of such contracts. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 30, 2012 and +July 2, 2011 (in thousands): +Derivatives Designated as Hedging +Instruments +Balance Sheet Location +June 30, 2012 +Fair Value +July 2, 2011 +Fair Value +Foreign currency forward contracts +Other current assets +$ +199 +$ +1,645 +Foreign currency forward contracts +Other long term assets +$ +659 +$ +1,078 +Foreign currency forward contracts +Other current liabilities +$ +(923 +) +$ +— +Foreign currency forward contracts +Other long term liabilities +$ +(928 +) +$ +(82 +) +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of Operations for +the fiscal year 2012 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +July 2, +2011 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Cost +of Sales +AOCI Balance +as of +June 30, +2012 +Settled foreign currency forward contracts +$ +1,035 +$ +(1,119 +) +$ +84 +$ +— +Unsettled foreign currency forward contracts +705 +(1,364 +) +— +(659 +) +Total +$ +1,740 +$ +(2,483 +) +$ +84 +$ +(659 +) +48 +Table of Contents +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of +Operations for the fiscal year 2011 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as +of +July 3, 2010 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as +of +July 2, 2011 +Settled foreign currency forward contracts +$ +279 +$ +1,253 +$ +(1,532 +) +$ +— +Unsettled foreign currency forward contracts +(521 +) +2,261 +— +1,740 +Total +$ +(242 +) +$ +3,514 +$ +(1,532 +) +$ +1,740 +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of Operations for +the fiscal year 2010 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as +of +June 27, 2009 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as +of +July 3, 2010 +Settled foreign currency forward contracts +$ +912 +$ +912 +$ +(1,824 +) +$ +— +Unsettled foreign currency forward contracts +— +(242 +) +— +(242 +) +Total +$ +912 +$ +670 +$ +(1,824 +) +$ +(242 +) +The Company does not enter into derivative instruments for trading or speculative purposes. The Company’s +counterparties to the foreign currency forward contracts are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual +obligations is remote. +As of June 30, 2012, the Company does not have any foreign exchange contracts with credit-risk-related contingent +features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from its China operations. The Company does not currently manage these risk exposures by using derivative +instruments. +11. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated +regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 30, +2012, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services. +Products and Services +Of the revenues for the years ended June 30, 2012, July 2, 2011, and July 3, 2010, EMS sales and services were $343.7 +million, $249.9 million, and $195.1 million, respectively. Keyboard sales for the years ended June 30, 2012, July 2, 2011, and July 3, 2010 were $2.8 million, $3.9 million, and $4.5 million, respectively. +Geographic Areas +Net sales and +long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 30, 2012, July 2, 2011, and July 3, 2010 are summarized in the following table. Net sales set forth below are based on the +shipping destination. +49 +Table of Contents +Domestic (U.S.) +Foreign +Total +(in thousands) +2012 +Net sales +$ +205,668 +$ +140,807 +$ +346,475 +Long-lived assets +$ +1,660 +$ +15,646 +$ +17,306 +2011 +Net sales +$ +172,778 +$ +81,068 +$ +253,846 +Long-lived assets +$ +1,588 +$ +13,329 +$ +14,917 +2010 +Net sales +$ +163,915 +$ +35,705 +$ +199,620 +Long-lived assets +$ +931 +$ +12,967 +$ +13,898 +For the year ended June 30, 2012, 70.9% of the Company’s foreign net sales were to customers in Canada, 12.5% +were to Australia, 5.4% were to Switzerland, 3.9% were to England, 1.5% were to New Zealand, and the remaining 5.8% were spread among customers in other parts of Europe and Asia. +For the year ended July 2, 2011, 50.7% of the Company’s foreign net sales were to customers in Canada, 24.4% were to Australia, 6.9% were to Switzerland, 6.1% were to England, 5.1% were to New +Zealand, and the remaining 6.8% were spread among customers in other parts of Europe and Asia. +For the year ended July 3, 2010, 48.8% of +the Company’s foreign net sales were to customers in Canada, 16.9% were to Australia, 13.9% were to China, and the remaining 20.4% were spread among customers in other parts of Europe and Asia. +Significant Customers +The percentage of +net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2012 +2011 +2010 +2012 +2011 +Customer A +29 +% +15 +% +* +% +30 +% +21 +% +Customer B +17 +% +16 +% +12 +16 +% +14 +% +Customer C +16 +% +16 +% +18 +20 +% +20 +% +Customer D +* +* +10 +% +* +* +* +Amount was less than 10% of total. +There can +be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the +Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and +adversely affect the Company’s business, operating results and financial condition. +50 +Table of Contents +12. QUARTERLY FINANCIAL DATA +Year Ended June 30, 2012 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +69,761 +$ +84,454 +$ +95,527 +$ +96,733 +Gross profit +5,005 +6,868 +8,724 +9,239 +Income before income taxes +1,512 +2,671 +4,562 +5,096 +Net income +1,247 +3,174 +3,394 +3,811 +Earnings per common share-basic +$ +0.12 +$ +0.30 +$ +0.32 +$ +0.36 +Earnings per common share-diluted +$ +0.12 +$ +0.30 +$ +0.32 +$ +0.35 +Weighted average shares outstanding +Basic +10,418 +10,447 +10,447 +10,474 +Diluted +10,446 +10,479 +10,762 +10,843 +Year Ended July 2, 2011 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +63,340 +$ +61,038 +$ +63,424 +$ +66,044 +Gross profit +5,970 +5,446 +4,229 +5,003 +Income before income taxes +2,552 +1,640 +765 +1,525 +Net income +1,742 +1,733 +724 +1,537 +Earnings per common share-basic +$ +0.17 +$ +0.17 +$ +0.07 +$ +0.15 +Earnings per common share-diluted +$ +0.17 +$ +0.17 +$ +0.07 +$ +0.15 +Weighted average shares outstanding +Basic +10,296 +10,345 +10,353 +10,380 +Diluted +10,403 +10,448 +10,436 +10,435 +51 +Table of Contents +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our +management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, +processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate +the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management +carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange +Act Rule 13a-15(f). Based on our assessment, we believe that as of June 30, 2012, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our +management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable +assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize +that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness +to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment +of the effectiveness of our internal controls over financial reporting as of June 30, 2012. This assessment was based on the criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of +the Treadway Commission. Based on our assessment, we believe that as of June 30, 2012, the Company’s internal control over financial reporting is effective based on that criteria. +This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to +attestation by our registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this annual report. +Changes in Internal Control over Financial Reporting +There have been no significant +changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 30, 2012 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial +reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +Item 9B: +OTHER INFORMATION +None +52 +Table of Contents +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the +Company is incorporated by reference from the Company’s definitive proxy statement for the 2012 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the +Company’s 2012 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction +3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2012 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies +to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of +Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2012 Proxy Statement is incorporated herein by this reference. +53 +Table of Contents +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 30, 2012. +EQUITY COMPENSATION PLAN INFORMATION +Plan category +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 reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +777,693 +$ +5.38 +— +Equity compensation plans not approved by security holders (2) +6,667 +$ +2.81 +— +Total +784,360 +$ +5.36 +— +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. As a +result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +(2) +Consists of the Key Tronic Corporation 2000 Employee Stock Option Plan. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2012 Proxy Statement is incorporated herein by this reference. +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, +and “Directors’ Independence” in the Company’s 2012 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2012 Proxy Statement is incorporated herein by this reference. +54 +Table of Contents +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in +Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +29 +Consolidated Balance Sheets, as of June 30, 2012, and July 2, 2011 +30 +Consolidated Statements of Income for the years ended June 30, 2012, July +2, 2011 and July 3, 2010 +31 +Consolidated Statements of Comprehensive Income for the years ended June 30, 2012, July +2, 2011 and July 3, 2010 +32 +Consolidated Statements of Shareholders’ Equity for the years ended June 30, 2012, +July 2, 2011 and July 3, 2010 +33 +Consolidated Statements of Cash Flows for the years ended June 30, 2012, July +2, 2011 and July 3, 2010 +34 +Notes to Consolidated Financial Statements +35-51 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +59 +Other schedules are omitted because of the absence of conditions under which they are required, or because required +information is given in the financial statements or notes thereto. +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), +pages 14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, +2000 +55 +Table of Contents +10.7* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.8* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.9 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April +26, 2005 +10.10 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the +Company’s Form 8-K filed June 6, 2005 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, +2005 +56 +Table of Contents +10.12* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2007, incorporated by reference to the Company’s Form 8-K filed July 28, +2006 +10.13* +Summary of Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s Form 8-K filed July 28, +2006 +10.14* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, +2005 +10.15 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form +8-K filed October 12, 2006 +10.16 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form +8-K filed November 20, 2006 +10.17 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed +January 5, 2007 +10.18 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April +11, 2007 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards +incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.20* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and +Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.21* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and +Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.22 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.23* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.25 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the +Company’s Form 10-K for the year ended July 3, 2010 +10.26* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and +Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2011 +57 +Table of Contents +10.27* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; +incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 +10.28 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on January 30, +2012 +10.29* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, and of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the +Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and +Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 +or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +58 +Table of Contents +PART IV +SCHEDULE II +KEY TRONIC CORPORATION AND +SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 30, 2012, JULY 2, 2011, AND JULY 3, 2010 +2012 +2011 +2010 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +732 +$ +1,303 +$ +409 +Provisions +762 +299 +2,182 +Dispositions +(348 +) +(870 +) +(1,288 +) +Balance at end of year +$ +1,146 +$ +732 +$ +1,303 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +111 +$ +111 +$ +111 +Provisions +— +15 +— +Write-offs +(111 +) +(15 +) +— +Balance at end of year +$ +— +$ +111 +$ +111 +59 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this +report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 10, 2012 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief +Executive Officer +(Principal Executive Officer) +60 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been +signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 10, 2012 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Ronald F. Klawitter +September 10, 2012 +Ronald F. Klawitter +Date +Director and Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Brett R. Larsen +September 10, 2012 +Brett R. Larsen +Date +Vice President of Finance and Controller +(Principal Accounting Officer) +/s/ James R. Bean +September 10, 2012 +James R. Bean, Director +Date +/s/ Dale F. Pilz +September 10, 2012 +Dale F. Pilz, Director and Chairman of the Board +Date +/s/ Yacov A. Shamash +September 10, 2012 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 10, 2012 +Patrick Sweeney, Director +Date +61 \ No newline at end of file diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/filing_metadata.csv b/raw/filings/0000719733/2012/0001193125-12-386435/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..bb0098cf581321a8226ad21c5639ddf25ab05185 --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2012-09-10,2012-06-30,2012-09-10T18:37:38.000Z,0001193125-12-386435,d372869d10k.htm,FORM 10-K,7318974,1,0,https://www.sec.gov/Archives/edgar/data/719733/000119312512386435/d372869d10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000119312512386435/,2012,2012,1 diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/item1.txt b/raw/filings/0000719733/2012/0001193125-12-386435/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..16ef6a5369f4b9c5da1355d243298f25dd1bac14 --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/item1.txt @@ -0,0 +1,206 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: +KeyTronicEMS Co.), was organized in 1969 as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for +computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth +through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on +keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to +contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, and precision plastics combined with +high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion +of the EMS industry has allowed us to continue to expand our customer base and the industries that we serve. The challenging global macroeconomic environment has had a negative impact on previously held customer programs. However, we are +successfully confronting the challenging global macroeconomic environment by controlling our costs and winning new customer programs, which allowed us to increase our profitability and maintain a strong balance sheet during the global economic +downturn. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer +portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, assembly, component selection, sourcing and procurement, worldwide +logistics, and new product testing and production all at competitive pricing due to our global footprint. +We believe that we are well +positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, centralized management, and core strengths continue to support our growth and our +customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our +customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential +customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a +concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing +challenges that we face include the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while +developing competitive pricing strategies, and successfully transitioning new program wins to full production during a time of macroeconomic uncertainty. +3 +Table of Contents +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin +through hole capability for printed circuit board assembly, tool making, precision plastic molding, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have historically not been seasonal in nature, but may be seasonal in the future if there are changes in the types +of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years ended June 30, 2012, July 2, 2011, and July 3, 2010, the five largest customers in each year accounted for 73%, 62%, +and 57% of combined total net sales, respectively. At the end of fiscal year 2012, we were generating revenue from 165 separate programs and 48 distinct customers as compared to 119 programs and 33 customers at the end of fiscal year 2011. As these +new customers’ sales ramp and new programs are won our concentration of revenue should decrease in the future. +The following table +represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales +by Fiscal Year +2012 +2011 +2010 +Customer A +29 +% +15 +% +* +% +Customer B +17 +% +16 +% +12 +% +Customer C +16 +% +16 +% +18 +Customer D +* +* +10 +% +* +Amount was less than 10% of total. +Although +keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We realized revenues of approximately $2.8 million, $3.9 million, and $4.5 million in fiscal years +2012, 2011, and 2010, respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate +availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales +people and distributors. Although we maintain relationships with several independent sales organizations to assist in marketing our EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +We have continually made +investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board +assemblies. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing +processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, +depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, automated +switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us +to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation +of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +4 +Table of Contents +We purchase materials and components for our products from many different suppliers, including both domestic +and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed +to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program +materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have +substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and +development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of +outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks and Patents +Our name and +logo are federally registered trademarks, and we believe they are valuable assets of our business. During 2001, we began operating under the trade name “KeyTronicEMS” to better identify our primary business concentration. We also own +several keyboard patents; however, since our focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +We consider our employees to be our primary strength and we make considerable +efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical +services, and meals to all of our employees in foreign locations. We maintain a 401(k) plan for U.S. employees, which provides a discretionary matching company contribution of up to 4% of an employee’s salary. We provide group health, life, and +disability insurance plans. We also maintain stock option plans and other long term incentive plans for certain employees and outside directors. +As of June 30, 2012 we had 2,700 employees compared to 1,997 on July 2, 2011, and 2,036 on July 3, 2010. Since we can have significant fluctuations in product demand, we seek to maintain +flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 28, 2012 our order backlog was valued at approximately $83.1 million, +compared to approximately $54.9 million on July 30, 2011. Even though our order backlog is comprised of firm purchase orders, the amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future +sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we +will attempt to negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due +to design modifications, customer forecast changes, or other customer requirements. +5 +Table of Contents +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 11, “Enterprise-Wide Disclosures” of the consolidated financial +statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +53 +President and Chief Executive Officer +Ronald F. Klawitter +60 +Executive Vice President of Administration, Chief Financial Officer and Treasurer +Douglas G. Burkhardt +54 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +50 +Executive Vice President of Business Development +Lawrence J. Bostwick +60 +Vice President of Engineering and Quality +Brett R. Larsen +39 +Vice President of Finance and Controller +Frank Crispigna III +51 +Vice President of Materials +Duane D. Mackleit +44 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age +53, has been President and Chief Executive officer of the Company since April 2009. Previously he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and +Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held +various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of +Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +RONALD F. +KLAWITTER – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Klawitter, age 60, has been +Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary, and Treasurer of the Company from October 1995 to July 1997. He was Acting Secretary from November 1994 to +October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President of Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. Mr. Klawitter has a BA +degree from Wittenberg University and is a Certified Public Accountant. +6 +Table of Contents +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 54, has been Executive Vice President of Worldwide Operations of the Company since July 22, 2010. Previously +Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China +Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, +Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 +years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 50, has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice +President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to +July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From +1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. +Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 60, has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate +Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He +is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. +Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +BRETT R. LARSEN – Vice President of Finance, and Controller +Mr. Larsen, age 39, has served as Vice President of Finance and Controller since February 2010. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From +October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, +Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting +and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +FRANK CRISPIGNA III – Vice +President of Materials +Mr. Crispigna, age 51, has been Vice President of Materials of the company since October 2011. Prior to this, +Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and +a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 44, has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July +2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key +Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +7 +Table of Contents +Available Information +Our principal executive offices are located at N. 4424 Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at +http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information +presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. \ No newline at end of file diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/item13.txt b/raw/filings/0000719733/2012/0001193125-12-386435/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..886a3370596d05158a6f3e696b17f75f90e97e49 --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/item13.txt @@ -0,0 +1,4 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, +and “Directors’ Independence” in the Company’s 2012 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/item9a.txt b/raw/filings/0000719733/2012/0001193125-12-386435/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..9f6a6fe31199409d5d278b94d827d1f76fbd0984 --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/item9a.txt @@ -0,0 +1,25 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our +management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, +processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate +the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management +carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange +Act Rule 13a-15(f). Based on our assessment, we believe that as of June 30, 2012, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our +management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable +assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize +that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness +to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment +of the effectiveness of our internal controls over financial reporting as of June 30, 2012. This assessment was based on the criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of +the Treadway Commission. Based on our assessment, we believe that as of June 30, 2012, the Company’s internal control over financial reporting is effective based on that criteria. +This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to +attestation by our registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this annual report. +Changes in Internal Control over Financial Reporting +There have been no significant +changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 30, 2012 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial +reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). \ No newline at end of file diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/rp_note.txt b/raw/filings/0000719733/2012/0001193125-12-386435/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2012/0001193125-12-386435/rpt_disclosure.txt b/raw/filings/0000719733/2012/0001193125-12-386435/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..9503db3b842ac1bced5df2124db0ad497a00a66d --- /dev/null +++ b/raw/filings/0000719733/2012/0001193125-12-386435/rpt_disclosure.txt @@ -0,0 +1,14 @@ +Related Person Transactions +In April +2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an +“Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount +involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a +less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was +(since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater +than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, +mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will +take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the +Related Party’s interest in the Transaction. +6 \ No newline at end of file diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/filing.txt b/raw/filings/0000889900/2000/0000950134-01-001886/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..10f403e6f65012e8e59ebe789aced7b0332d57fa --- /dev/null +++ b/raw/filings/0000889900/2000/0000950134-01-001886/filing.txt @@ -0,0 +1,3713 @@ +10-K405 +1 +d84623e10-k405.txt +FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000 +1 +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +UNITED STATES SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +--------------------- +FORM 10-K +--------------------- +(MARK ONE) +[X]ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE +ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 +OR +[ ] +TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE +ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO +COMMISSION FILE NUMBER 0-22664 +--------------------- +PATTERSON ENERGY, INC. +(Exact name of registrant as specified in its charter) +DELAWARE 75-2504748 +(State or other jurisdiction of (I.R.S. Employer Identification No.) +incorporation or organization) +P.O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS 79550 +(Address of principal executive offices) (Zip Code) +--------------------- +Registrant's telephone number, including area code: (915) 573-1104 +--------------------- +Securities Registered Pursuant to 12(b) of the Act: None +Securities Registered Pursuant to 12(g) of the Act: +Preferred Stock Purchase Rights +(TITLE OF CLASS) +Common Stock, $.01 Par Value +Indicate by check mark whether the registrant (1) has filed all reports +required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the +registrant was required to file such reports), and (2) has been subject to such +filing requirements for the past 90 days. Yes [X] No [ ] +Indicate by check mark if disclosure of delinquent filers pursuant to Item +405 of the Regulation S-K is not contained herein, and will not be contained, to +the best of the registrant's knowledge, in definitive proxy or information +statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K [X] +The aggregate market value of the voting and non-voting common equity held +by non-affiliates of the registrant as of March 1, 2001 was $1,345,204,584, +based upon the average bid and asked prices of $35.94 and $36.06, respectively, +on the Nasdaq National Market. +As of February 27, 2001, the registrant had outstanding 38,049,706 shares +of common stock, $.01 par Value, its only class of voting stock. +PART OF +FORM 10-K DOCUMENT INCORPORATED BY REFERENCE +--------- ---------------------------------- +PART III Portions of proxy statement to be filed pursuant to Schedule +14A relating to election of directors. +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +2 +PART I +Patterson may from time to time make written or oral forward-looking +statements, including statements contained in our filings with the Securities +and Exchange Commission ("SEC") and or reports to stockholders. Items 1 and 2 +contain forward-looking statements and 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: +- utilization rates of drilling rigs, +- crude oil and natural gas prices, +- volatility of dayrates for contract services, +- drilling and completion of wells, +- well operations, +- drilling and completion fluids services, +- business strategies and other plans and objectives of our management for +future operations and activities, +- capital needs, and +- reserve estimates (including estimates for future net revenues associated +with such reserves and the present value of such future net reserves). +The words "believes," "budgeted," "expects," "project," "will," "could," "may," +"plans," "intends," "strategy," or "anticipates," and similar expressions used +in this document identify forward-looking statements. We do not undertake to +update, revise or correct any of the forward-looking information. Readers are +cautioned that such forward-looking statements should be read in conjunction +with our disclosures under the heading: "Cautionary Statement for Purposes of +the 'Safe Harbor' Provisions of the Private Securities Litigation Reform Act of +1995" beginning on page 20. +------------------------------ +ALL NUMERICAL INFORMATION CONTAINED IN THIS REPORT RELATING TO PATTERSON +COMMON SHARES REFLECTS THE TWO-FOR-ONE SPLITS OF ITS COMMON STOCK IN JULY 1997 +AND IN JANUARY 1998. +------------------------------ +ITEMS 1 AND 2. BUSINESS AND PROPERTIES. +OVERVIEW +Patterson is one of the leading providers of domestic land-based drilling +services to major and independent oil and natural gas companies. Formed in 1978 +and reincorporated in 1993 as a Delaware corporation, we focus our operations +in: +- Texas, +- New Mexico, +- Oklahoma, +- Louisiana, +- Mississippi, and +- Utah. +2 +3 +We currently have a drilling fleet of 152 drilling rigs, 140 of which are +currently marketable. A drilling rig includes the structure, power source and +machinery necessary to cause a drill bit to penetrate rock to a depth desired by +the customer. A marketable drilling rig is a rig that is fully operable. +We provide contract drilling and completion fluids services to other oil +and natural gas operators. Drilling and completion fluids are used by oil and +natural gas operators during the drilling process to control pressure when +drilling oil and natural gas wells. We are also engaged in the development, +exploration, acquisition and production of oil and natural gas. +CONTRACT DRILLING OPERATIONS. We have established a reputation for +reliable, high quality drilling equipment and well-trained crews. We continually +seek to modify and upgrade our equipment to maximize the performance and +capabilities of the drilling rig fleet, which we believe provides us with a +competitive advantage. Additionally, we have the in-house capability to design, +manufacture, refurbish, repair and modify our drilling rigs. Of our drilling +rigs, 95 are capable of drilling to depths of 12,000 feet and greater, including +52 that are capable of drilling to 15,000 feet and greater. During fiscal year +2000, we drilled 1,485 wells for 224 non-affiliated customers maintaining an +average rig utilization rate of 74%. A rig is utilized when it is operating or +being moved, assembled or dismantled under contract. +Over the past several years, our operations have expanded through a series +of acquisitions. Since 1993, when we had 13 drilling rigs, we have increased our +contract drilling fleet through acquisitions to 152 drilling rigs. From 1993 +(prior to giving effect to the 1996 merger with Tucker Drilling Company, Inc. +which was treated as a pooling of interests for financial accounting purposes) +through 2000, our consolidated operating revenues have increased from $25.0 +million to $307.9 million. +OIL AND NATURAL GAS OPERATIONS. Our oil and natural gas activities are +designed to complement our land drilling operations and diversify our overall +business strategy. These activities are primarily focused in mature producing +regions in the Permian Basin and South Texas. Oil and natural gas operations +comprised approximately 5% of our consolidated operating revenues for the year +2000. At December 31, 2000, our proved developed reserves were approximately 1.8 +million BOE and had a present value (discounted at 10% before income taxes) of +estimated future net revenues of approximately $22.8 million. +The business strategy for our oil and natural gas operations is to increase +our oil and natural gas reserves primarily through developmental and exploratory +drilling in producing areas. Although, from time to time, we will participate +through a working interest in an exploratory well, the focus of our drilling +activities for the foreseeable future in our oil and natural gas operations will +be developmental drilling in the Permian Basin of West Texas and Southeastern +New Mexico and in South Texas. +DRILLING AND COMPLETION FLUIDS OPERATIONS. We also provide contract +drilling and completion fluids services to numerous operators in the oil and +natural gas industry. Operating revenues derived from these activities +constituted approximately 10% of our consolidated operating revenues. We believe +that these contract services integrate well with our other core operating +activities. Our drilling fluids operations began with the acquisitions of Lone +Star Mud, Inc., during January 1998 and Tejas Drilling Fluids, Inc., in +September 1998. These operations are conducted in the Permian Basin of West +Texas, Southeast New Mexico and South Texas. We further expanded our contract +services for drilling fluids, as well as added services for completion fluids, +with our acquisition of the drilling and completion fluids division of Ambar, +Inc., in October 2000. These operations are principally located in Lafayette, +Louisiana, with numerous stockpoint facilities strategically located in +Oklahoma, New Mexico, along the southern coasts of Louisiana and Texas and the +Gulf Coast area of South Texas. +------------------------------ +On February 5, 2001, we announced that our board of directors along with +the board of directors of UTI Energy Corp., approved a merger of the two +companies with Patterson as the surviving entity. According to the terms of the +merger agreement between UTI and Patterson, stockholders of UTI will receive one +common share of Patterson for each common share of UTI, and Patterson will +assume UTI's outstanding options and warrants. The board of directors of the new +company will consist of eleven directors, six of whom will be +3 +4 +selected by Patterson from its existing board and five of whom will be selected +by UTI. Although the merger agreement does not specify who will be the officers +of the new company, we expect that Mark S. Siegel, UTI's Chairman of the Board, +would be the Chairman of the Board, and Cloyce A. Talbott, Patterson's Chairman +of the Board and Chief Executive Officer, would be Chief Executive Officer. The +combined company will be the second largest United States land-based drilling +service contractor with 302 drilling rigs and is expected to be called +"Patterson-UTI Energy, Inc." +Under the terms of the merger agreement, both UTI and Patterson have agreed +not to solicit competing offers, but the boards of directors of each company are +free to consider and accept an unsolicited offer if, based on the advice of +counsel, it believes it must do so in the exercise of its fiduciary duty. In the +event a party accepts an unsolicited offer, or its board of directors withdraws +its recommendation in light of an unsolicited offer or the stockholders do not +vote to approve the merger because of an unsolicited offer, the other party +would be entitled to receive a breakup fee of $32.5 million plus reimbursement +of expenses of up to $2.5 million. In the event the stockholders of one party do +not vote to approve the merger and the other party is not in default and is +ready, willing and able to perform its agreement, the party whose stockholders +vote against the merger will be required to pay to the other party $2.5 million, +plus up to an additional $2.5 million in expenses. +------------------------------ +BUSINESS STRATEGY +Our strategy is to increase cash flow and earnings per share by enhancing +our position as a leading domestic land-based drilling contractor. The principal +components of this strategy are as follows: +- STRONG INDUSTRY REPUTATION. We believe that Patterson has a strong +reputation within our existing markets for providing well maintained +equipment, high quality service and experienced personnel. We intend to +build on existing customer relationships in each of our areas of +operations by offering technically sophisticated drilling equipment and +providing quality service to our customers with an emphasis on +efficiency, dependability and safety. +- HIGH QUALITY ASSET BASE. Our drilling rigs are maintained in good +operating condition through an established program of modifications and +upgrades. We believe that the quality and operating condition of our +drilling equipment allows us to maximize utilization rates and pricing. +- CONTINUED GROWTH THROUGH ACQUISITION. We believe that attractive +acquisition opportunities continue to exist to further expand our +drilling rig fleet in our core geographic operating areas as well as into +other areas. Following an acquisition, we refurbish the acquired drilling +rigs to our standards of quality and dependability. +- EFFICIENT OPERATIONS. Based on publicly available information, we +believe that we had one of the most competitive ratios of EBITDA to +revenues in the U.S. land-based drilling industry during 2000. We +produced these results from the combination of providing premium contract +drilling services and operating under an efficient cost structure. In +addition, we have achieved cost reductions and efficiencies through +acquisition-related synergies. Furthermore, we use our fleet of trucks +and trailers to rig down, transport and rig up our drilling rigs, which +further increases efficiency by reducing the time and costs associated +with these ancillary operations. +RECENT ACQUISITIONS +Jones Drilling Corporation. On January 5, 2001, we completed the +acquisition of Jones Drilling Corporation and the assets of three related +entities, Henderson Welding, Inc., L.E.J. Truck and Crane, Inc., and L.E. Jones +Drilling Company. Each of the four companies were based in Duncan, Oklahoma. The +assets acquired as a part of these transactions consisted of: +- 21 contract drilling rigs, 14 of which are marketable, +- a fleet of rig moving trucks, +4 +5 +- drilling facilities, and +- shops and equipment yards located in Duncan, Oklahoma, and Bridgeport, +Texas. +The drilling rigs range from 450 to 1,000 horsepower with 12 rigs having a +drilling capacity of 12,000 feet and greater, with four of those rigs capable of +drilling to depths greater than 15,000 feet. The purchase price consisted of +810,070 shares of our common stock valued at $26.8125 per share and $10.9 +million cash, net of certain working capital adjustments. The common shares have +been registered for resale with the SEC. +Ambar, Inc. On October 3, 2000, we acquired, through a wholly-owned +subsidiary, certain assets and assumed certain liabilities of the drilling and +completion fluids division of Ambar, Inc. Ambar was a privately owned company +with principal operations in Louisiana, the Gulf Coast region of South Texas and +the Gulf of Mexico. Pursuant to the transaction, we acquired working capital of +approximately $7.8 million (current assets of $18.2 million and current +liabilities assumed of $10.4 million), fixed assets valued at $15.7 million and +other trademarks and intellectual property specific to the division's +operations. Consideration paid included cash of $12.4 million after a $3.9 +million credit for certain working capital adjustments and included $680,000 of +direct costs incurred related to the acquisition. +High Valley Drilling, Inc. On June 2, 2000, we closed the acquisition of +High Valley Drilling, Inc., a privately-owned, non-affiliated company based in +Oklahoma City, Oklahoma. The assets consisted of eight non-marketable drilling +rigs and other related equipment. The drilling rigs, when completely +refurbished, will have depth capacities of at least 15,000 feet, with three of +the rigs expected to have a depth rating of 25,000 feet. By the end of 2000, +four of the rigs had been placed into service with two additional rigs placed +into service during February 2001. Consideration for the acquisition consisted +of 1,150,000 restricted shares of our common stock, three-year warrants to +acquire an additional 127,000 shares at an exercise price of $22.00 per share +and $208,000 of direct costs incurred related to the acquisition. The shares and +warrant shares have been registered for resale with the SEC. Our common shares +were valued at $18.00 per share for purposes of recording the acquisition as a +purchase. This value represented the market price of the shares on the day the +acquisition was announced. Using a Black-Scholes model, the warrants were valued +at $900,000 for purposes of this transaction. +WEK Drilling Co., Inc. On March 31, 2000, we acquired WEK Drilling +Company, Inc., a privately-owned, non-affiliated company based in Southeast New +Mexico. The purchase price for WEK totaled $6.8 million which is net of cash +acquired, and $77,000 of direct costs incurred related to the acquisition. The +assets acquired included four marketable land-based drilling rigs and other +related equipment and working capital of approximately $1.2 million. Three of +the rigs have depth capacities greater than 12,000 feet and one has a depth +rating of 10,500 feet. The acquisition was funded using $5.66 million of +proceeds from our credit facility and 53,000 shares of our common stock valued +at $29.0625 per share based on the average trading price of the Company's common +stock 10 trading days prior to consummation. Certain assets, unrelated to the +drilling business, were resold to one of the former WEK owners for $1.0 million +cash. The common shares have been registered for resale with the SEC. +INDUSTRY SEGMENTS +Our revenues, operating profits and identifiable operating assets are +primarily attributable to three industry segments: +- contract drilling, +- oil and natural gas exploration, development, acquisition and production, +and +- drilling and completion fluids services. +With respect to these three segments: +- the contract drilling segment had an operating profit in 1998 and 2000, +and an operating loss for the year 1999, +5 +6 +- the oil and natural gas segment had an operating profit in 1999 and 2000, +and an operating loss for the year 1998, and +- the drilling and completion fluids segment had an operating profit in +1998, and an operating loss in 1999 and 2000. +See "Management's Discussion and Analysis of Financial Condition and Results of +Operations" and Note 14 of Notes to Consolidated Financial Statements included +as a part of Items 7 and 8, respectively, of this document for financial +information pertaining to these industry segments. +CONTRACT DRILLING OPERATIONS +GENERAL. We market our contract drilling services to major oil companies +and independent oil and natural gas producers. We currently own 152 drilling +rigs, 140 of which are currently marketable, with: +- 99 based in Texas (49 in West Texas, 27 in South Texas, 12 in East Texas +and 11 in North Texas), +- 20 based in New Mexico, +- nine based in Oklahoma, +- four based in Louisiana, +- four based in Utah, and +- four based in Mississippi. +Fifteen of our drilling rigs are diesel electric rigs, all of which are +marketable, and 137 of our drilling rigs are mechanical rigs of which, 125 rigs +are considered marketable. 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. Our drilling rigs have rated +maximum depth capabilities ranging from 8,000 feet to 25,000 feet. +Our marketable drilling rigs are equipped with: +- engines, +- drawworks or hoists, +- derricks or masts, +- pumps to circulate the drilling fluid, +- blowout preventers, +- drill string (pipe), and +- related equipment. +Depth of the well and drill site conditions are the principal factors in +determining the size and type of drilling rig used for a particular job. Our +drilling rigs are utilized for both exploratory and developmental drilling and +can be used for either vertical or horizontal drilling. +In order to drill a well, the operator of the well assembles a number of +different contractors to provide the necessary services. Included among these +contractors are the drilling contractors, such as Patterson, plus other +contractors specializing in such matters as logging, completion and, in the case +of horizontal wells, specialists in the technical aspects of such drilling. +We have achieved our current position as a leading provider of contract +drilling services in our areas of operations by providing high quality services +to our customers at competitive rates. Although generally of lesser importance +than price, we believe that the condition of a drilling fleet, the reputation of +the contract driller and the quality and experience of the drilling supervisors +in the field have significant importance to prospective customers. We will +continue to strive to maintain our drilling fleet in good working condition. +6 +7 +In addition to normal repair and maintenance expenses, we spend significant +funds each year on an ongoing program of modifying and upgrading our drilling +rigs. We also strive to employ experienced and dedicated drilling supervisors +for our various drilling rigs in the field. We intend to continue our ongoing +rig maintenance program and to retain high quality, experienced drilling +supervisors in order to build upon our reputation in the market place. In +addition, if favorable opportunities arise, we may seek to further expand our +drilling rig fleet through selected acquisitions. +DRILLING CONTRACTS. Most of our drilling contracts are with established +customers and are obtained on a competitive bid basis. Some contracts are +obtained on a negotiated basis. Generally, the contracts are entered into for +short-term periods and cover the drilling of a single well with the terms and +rates varying depending upon the nature and duration of the work, the equipment +and services supplied and other matters. +The drilling contracts obligate us to pay certain operating expenses, +including wages of drilling personnel and necessary maintenance expenses to +furnish incidental drilling rig supplies and equipment. The contracts are +subject to termination by the customer on short notice, usually upon payment of +a fee. We generally indemnify our customers against claims by our employees and +claims arising from surface pollution caused by spills of fuel, lubricants and +other solvents within our control. The customers generally indemnify us against +claims arising from other surface and subsurface pollution, except claims +arising from our own gross negligence. +The contracts provide for payment on a daywork, footage or turnkey basis, +or a combination thereof. Our bids for each contract depend upon: +- the anticipated complexity of drilling the well, +- the on-site drilling conditions, +- the type of equipment to be used, +- our estimate of the risks involved, +- the estimated duration of the work to be performed, and +- other considerations. +All of the horizontal wells we have drilled have been priced either on a +turnkey or footage basis during the vertical drilling phase and on a daywork +basis beyond that point. +Under daywork contracts, we provide the drilling rig, including the +required personnel, to the operator. The operator then supervises the drilling +of the contracted well. Our compensation is based on a negotiated rate per day +during the period the drilling rig is utilized. Daywork contracts generally +specify: +- the type of equipment to be used, +- the size of the hole, and +- the proposed depth of the well. +Under a daywork contract, we continue to earn revenue, even though drilling +may be temporarily suspended (such as time delays for various reasons, including +stuck drill strings and blow-outs). +Footage contracts usually require us to bear some of the drilling costs in +addition to providing the drilling rig. Under a footage contract, we would +normally determine the manner of drilling and type of equipment to be used, +subject to certain customer specifications. We would also bear the risk and +expense of: +- mechanical malfunctions, +- equipment shortages, and +- other delays arising from drilling problems. +7 +8 +Compensation under a footage contract is based on a rate-per-foot-drilled +basis at completion of the well. Prices of both footage and daywork contracts +vary depending upon various factors, such as: +- the location, depth, duration and complexity of the well to be drilled, +- operating conditions, and +- other factors particular to each proposed well. +Under turnkey contracts, we contract to drill a well to a certain depth +under specified conditions and provide most of the equipment and services +required. We bear the risk of drilling the well to the specified depth. In +return, our compensation is usually substantially greater than on wells we drill +on a daywork or footage basis. If severe drilling problems are encountered in +drilling wells under turnkey contracts, we would sustain substantial losses +under that contract. +The following table sets forth the approximate percentage of our drilling +revenues attributable to daywork, footage and turnkey contracts: +YEAR ENDED DECEMBER 31, +------------------------- +TYPE OF REVENUES 1998 1999 2000 +---------------- ---- ---- ---- +Daywork..................................................... 64% 58% 72% +Footage..................................................... 24 22 20 +Turnkey..................................................... 12 20 8 +At December 31, 2000, we had 100 wells in progress of which 94 were under +daywork contracts, 6 under footage contracts and there were no turnkey contracts +in place. +Contract drilling operations depend on the availability of: +- drill pipe, +- bits and other related rig equipment, +- fuel, and +- qualified personnel, some of which have been in short supply from time to +time. +As favorable buying opportunities arise, we stockpile drill pipe, bits and other +drilling rig parts. Currently, drill pipe, other rig equipment and rig personnel +are in short supply. +Our ability to drill wells for which we have contracts may be delayed by +inclement weather. Sustained periods of inclement weather may materially effect +our revenues and cash flows. +CONTRACT DRILLING ACTIVITY. The following table sets forth certain +information regarding our contract drilling activity for each of the last three +years: +YEAR ENDED DECEMBER 31, +----------------------- +1998 1999 2000 +---- ---- ---- +Number of wells drilled..................................... 1,028 842 1,485 +Average rigs available for service.......................... 106 114 119 +Average rig utilization rate(1)............................. 54% 45% 74% +--------------- +(1) Rig utilization is based on a 365-day year for rigs available for service +during 1998 and 1999, and a 366-day year for rigs available in 2000. A rig +is utilized when it is operating or being moved, assembled or dismantled +under contract. +CUSTOMERS. During the year 2000, we drilled wells for 224 non-affiliated +customers. This compares with 189 non-affiliated customers during the year 1999. +No single customer accounted for 10% or more of our consolidated operating +revenues during 2000. We do not believe that the loss of any one customer would +have a material adverse effect on our operations. +8 +9 +Our customers in the past 12 months have included, among others: +- Coastaldril Inc., +- Cross Timbers Operating, +- Devon Energy Production Company, L.P., +- EOG Resources, +- Fina Oil and Chemical, +- J.W. Operating Co., +- Louis Dreyfus Natural Gas, +- Matador Petroleum Corp., +- Mitchell Energy Corp., +- Oxy USA, Inc., +- Union Pacific Resource Company, +- United Oil and Minerals, Inc., and +- Yates Petroleum Corp. +At the end of 2000, we were drilling a total of 100 wells. Three of these +wells were being drilled for affiliated parties. +DRILLING RIGS AND RELATED EQUIPMENT. The following table provides certain +information concerning our drilling rigs as of December 31, 2000: +DIESEL +DEPTH RATING (FT.) MECHANICAL ELECTRIC +------------------ ---------- -------- +8,000 to 9,999.............................................. 25(1) -- +10,000 to 11,999............................................ 23 -- +12,000 to 14,999............................................ 33(2) 2 +15,000 and greater.......................................... 35(2) 13 +----- ---- +Totals............................................ 116 15 +===== ==== +--------------- +Note: The above table does not reflect the 21 drilling rigs acquired in January +2001. +(1) Includes three nonmarketable rigs. +(2) Includes two nonmarketable rigs. +We currently own 129 trucks and 152 trailers. This equipment is used to rig +down, transport and rig up our drilling rigs. This minimizes Patterson's +dependency upon third parties for these ancillary services and further enhances +the efficiency of our contract drilling operations. +Most repair work and overhaul of our drilling rig equipment is performed at +our yard facilities variously located in Texas, New Mexico and Oklahoma. We +believe that our marketable drilling rigs and related equipment are in good +operating condition. In addition to normal repair and maintenance expenses, we +have historically spent significant funds for our ongoing program of modifying +and upgrading our equipment. +9 +10 +OIL AND NATURAL GAS OPERATIONS +GENERAL. We have been engaged in the development, exploration, acquisition +and production of oil and natural gas since 1982. Our oil and natural gas +activities are designed to complement our land drilling operations and are +primarily concentrated in two operating areas: +- the Permian Basin of West Texas and Southeast New Mexico, and +- South Texas. +Our strategy for our oil and natural gas operations is to increase our +reserve base primarily through developmental drilling, as well as selected +acquisitions of leasehold acreage and producing properties. At the end of year +2000, we were the operator of 164 wells. +OIL AND NATURAL GAS RESERVES. We engaged M. Brian Wallace, P.E., Dallas, +Texas, an independent petroleum engineer, to estimate our proved developed +reserves, projected future production and estimated future net revenues from our +proved developed reserves as of the end of 1998, 1999 and 2000. Mr. Wallace's +estimates were based upon a review of production histories and other geologic, +economic, ownership and engineering data provided by us. In determining the +estimates of the reserve quantities that are economically recoverable, Mr. +Wallace used oil and natural gas prices and estimated average development and +production costs provided by us. +The following table sets forth information as of the end of 1998, 1999 and +2000, derived from the reserve reports of Mr. Wallace. The present values +(discounted at 10% before income taxes) of estimated future net revenues shown +in the table are not intended to represent the current market value of the +estimated oil and natural gas reserves owned by us. For further information +concerning the present value of estimated future net revenues from these proved +developed reserves, see Note 19 of the Notes to Consolidated Financial +Statements included as a part of Item 8 of this document. +AS OF DECEMBER 31, +-------------------------------- +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Proved Developed Reserves: +Oil (Bbls)....................................... 946 1,205 1,129 +Gas (Mcf)........................................ 3,490 4,118 3,880 +Total (BOE)...................................... 1,528 1,891 1,776 +Estimated future net revenues before income +taxes............................................ $ 9,232 $ 24,741 $ 31,891 +Present value of estimated future net revenues +before income taxes, discounted at 10%........... $ 6,770 $ 17,240 $ 22,801 +A barrel (Bbl) of oil is 42 U.S. gallons and represents the basic unit for +measuring production of crude oil and condensate. +An Mcf of natural gas refers to a volume of 1,000 cubic feet under +prescribed conditions of pressure and temperature and represents the basic unit +for measuring volumes of produced gas. A barrel of equivalent (BOE) in reference +to natural gas equivalents is determined using the rate of six Mcf of natural +gas (including natural gas liquids) to one Bbl of crude oil or condensate. +Proved oil and gas reserves are the estimated quantities of natural gas and +crude oil which geological and engineering data demonstrate with reasonable +certainty to be recoverable in future years from known reservoirs under existing +economic and operating conditions. Reserves are considered proved if economical +productibility is supported by either actual production or conclusive formation +tests. Reserves which can be produced economically through application of +improved recovery techniques are included in the "proved" classification when +successful testing by a pilot project or the operation of an installed program +in the reservoir provides support for the engineering analysis on which the +project or program was based. Proved developed oil and natural gas reserves can +be expected to be recovered through existing wells with existing equipment and +operating methods. +10 +11 +The reserve data set forth above represents only estimates. The estimates +are based on various assumptions and, therefore, are inherently imprecise. Our +actual future production, revenues, taxes, production costs and development +costs may vary substantially from those assumed in the estimates. Any +significant variance could materially affect the estimates set forth in this +document. In addition, the reserve data may be subject to upward or downward +revisions depending upon, among other factors, production history and prevailing +oil and natural gas prices. Oil and natural gas prices have fluctuated widely in +recent years. There is no assurance that prices will be higher or lower than +prices used in estimating our reserves. +PRODUCTION. Our wells in South Texas primarily produce natural gas and in +the Permian Basin primarily produce oil. The following table sets forth our: +- net oil and natural gas production, +- average sales price, and +- average production costs +associated with our production during the periods indicated. +YEAR ENDED DECEMBER 31 +------------------------------ +1998 1999 2000 +---- ---- ---- +Average net daily production: +Oil (Bbls)......................................... 835 698 752 +Gas (Mcf).......................................... 2,742 2,745 3,784 +Total (BOE)........................................ 1,292 1,156 1,383 +Average sales prices: +Oil (per Bbl)...................................... $ 12.16 $ 18.08 $ 29.99 +Gas (per Mcf)...................................... 1.93 2.22 3.87 +Average production (lifting) costs (per BOE)......... $ 4.08 $ 4.08 $ 6.41 +PRODUCTIVE WELLS. The following table sets forth information regarding the +number of productive wells in which we held a working interest as of the end of +2000. One or more completions in the same well bore are reflected as one well. +PRODUCTIVE WELLS +---------------- +GROSS NET +------ --- +Oil......................................................... 188 33.48 +Gas......................................................... 100 16.38 +--- ----- +Total............................................. 288 49.86 +=== ===== +A productive well is a well producing oil or natural gas in commercial +quantities. A working interest is the operating interest under an oil and +natural gas lease. It gives the owner the right to explore for and produce oil +and natural gas from the lease. +DEVELOPED AND UNDEVELOPED ACREAGE. The following table sets forth the +developed and undeveloped acreage in which we owned a working interest at the +end of 2000: +DEVELOPED UNDEVELOPED +--------------- --------------- +LOCATION GROSS NET GROSS NET +-------- ----- --- ----- --- +South Texas........................................ 43,702 8,264 45,785 10,739 +Permian Basin...................................... 19,594 3,101 17,186 2,282 +------ ------ ------ ------ +Total.................................... 63,296 11,365 62,971 13,021 +====== ====== ====== ====== +Undeveloped acreage is leased acres on which wells have not been drilled to +a point that would permit production of commercial quantities of oil and natural +gas. Developed acreage is leased acres that have been assigned to productive +wells. Our gross acreage is the total number of acres, developed or undeveloped, +in +11 +12 +which we own a working interest, regardless of the size of our working interest +in the acreage. Our net acreage is the gross acreage proportionally reduced by +our working interest in the acreage. +Many of our leases summarized in the table above as undeveloped acreage +will expire at the end of their respective primary terms unless production has +been obtained from the acreage prior to that date. If production is obtained, +the lease will remain in effect until the cessation of production. The following +table sets forth the gross and net acreage subject to leases summarized in the +table of undeveloped acreage that will expire: +LEASE ACRES EXPIRING +-------------------- +GROSS NET +----- --- +Years ending: +December 31, 2001........................................... 15,395 3,056 +December 31, 2002........................................... 6,400 1,605 +December 31, 2003 and later................................. 41,176 8,360 +------ ------ +Total............................................. 62,971 13,021 +====== ====== +DRILLING ACTIVITIES. The following table sets forth the results of our +participation in the drilling of developmental and exploratory wells during +1998, 1999 and 2000: +DEVELOPMENT WELLS EXPLORATORY WELLS +---------------------------- --------------------------- +PRODUCTIVE DRY HOLES PRODUCTIVE DRY HOLES +------------- ------------ ------------ ------------ +YEAR ENDED DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET +----------------------- ----- --- ----- --- ----- --- ----- --- +1998.................................. 23 4.45 6 1.74 3 .55 13 2.16 +1999.................................. 27 5.21 7 1.71 8 1.00 4 .48 +2000.................................. 16 3.63 14 3.33 4 .50 3 .57 +-- ----- -- ---- -- ---- -- ---- +Total....................... 66 13.29 27 6.78 15 2.05 20 3.21 +== ===== == ==== == ==== == ==== +Generally, a developmental well is a well that is drilled into an oil and +gas reservoir that is known to be productive. An exploratory well is a well that +is drilled to find oil and gas in an unproved area. +MARKETING OF CRUDE OIL AND NATURAL GAS. Crude oil is sold based upon +30-day automatically renewable contracts with oil purchasers. The actual prices +we realize vary as world oil prices fluctuate. Due to competitive conditions, we +do not believe that the loss of any one of our major crude oil purchasers would +have a material adverse effect on our business. We market oil produced from our +operated wells through a wholly-owned subsidiary. +Most of our natural gas is sold through third-party natural gas brokers at +spot market prices and is transported to market by interstate pipelines. +Contracts with these brokers are currently for less than five years and allow +for prices to adjust to the marketplace. We believe that, because of the +competitive nature of the industry today, the loss of any one of our natural gas +purchasers would not have a material adverse effect on our business. While we +have not experienced any inability to market our natural gas, if transportation +space in the pipelines is restricted or is unavailable, our cash flow from our +oil and natural gas operations would be adversely affected. +Historically, we have not entered into any derivative transactions to hedge +our production of oil and natural gas. +No customer for our oil and natural gas accounted for more than 10% of our +consolidated revenues for the year 2000. +TITLE TO OIL AND NATURAL GAS PROPERTIES. Title to our oil and natural gas +properties is subject to royalty, overriding royalty, carried working, and other +similar interests and cost sharing arrangements customary in the oil and natural +gas industry (including farmout agreements, operating agreements and joint +venture arrangements), liens for current taxes not yet due, and to other minor +defects and encumbrances. We believe +12 +13 +that such burdens do not materially detract from the value of such properties or +from our interest therein or materially interfere with the operation of our +business. +As is customary in the oil and natural gas industry in the case of +undeveloped properties, an in-house title review is made prior to or at the time +of acquisition. More comprehensive title investigations, including in most +cases, receipt of a title opinion of legal counsel, are generally made before +commencement of drilling operations on undeveloped properties and also are +generally made before consummation of an acquisition of developed properties. +DRILLING AND COMPLETION FLUIDS OPERATIONS +GENERAL. We provide drilling fluids, completion fluids and related +services to oil and natural gas producers in the Permian Basin of West Texas and +Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast regions +of Texas and Louisiana and the Gulf of Mexico. We are a technically oriented +supplier of drilling and completion fluids and target customers and projects +where technical expertise is more valued than product price. We serve our +land-based and offshore customers through seven stockpoints strategically +located along the Gulf of Mexico in Texas and Louisiana, and seven land-based +stockpoints in Louisiana, Texas, Oklahoma and New Mexico. +DRILLING FLUIDS. Our product sales are supported by a technical service +organization dedicated to product application on the customer's wellsite. +Drilling fluids products and systems are used to cool and lubricate the bit +during drilling operations, contain formation pressures (thereby preventing a +blowout), suspend and remove rock cuttings from the hole and maintain the +stability of the wellbore. Technical services are provided to ensure that the +products and systems are applied effectively to optimize drilling operations. +These services include: +- recommending products and services during the well planning phase, +- testing drilling fluid properties and recommending adjustments during the +drilling phase, and +- analyzing well results after the project is complete to improve the +performance of wells to be drilled in the future. +COMPLETION FLUIDS. After the well is drilled it undergoes the completion +process wherein the well casing is set and cemented in place. At that point, the +role of the drilling fluid is complete, and it is circulated out of the well and +replaced with completion fluid. +Completion fluids, also known as clear brine fluids, are solids-free, clear +salt solutions that have high specific gravities. Combined with a range of +specialty chemicals, these fluids are used by operators in the oil and natural +gas industry to control bottom-hole pressures and to meet a well's specific +corrosion, inhibition, viscosity, and fluid loss requirements during the +completion and workover phases. These systems are specially designed to maximize +well production by minimizing formation damage that can be caused by +solids-laden systems. We provide a complete line of completion fluids products +and services, including: +- a full range of low- and high-density brines, +- specialty chemicals, +- filtration and chemical treatment services used in the reclamation of +these specialized fluids, and +- technical engineering and laboratory support services. +OTHER SERVICES. In addition to the core drilling and completion fluids +business, we offer a broad range of on-site fluid filtration, handling and +recycling services. We also rent equipment related to our product and service +lines and provide dock services at our stockpoints that service offshore +operations. Rental products offered include portable liquid storage tanks for +use by offshore or onshore operators, cutting boxes used to transport well +cuttings, pumps and heavy equipment. +13 +14 +STOCKPOINTS. We serve our offshore customers through seven strategically +located coastal stockpoints, each with dockside loading capacities. Our offshore +service stockpoints are located in: +- Galveston (TX), +- Cameron (LA), +- Intercoastal City (LA), +- Berwick (LA), +- Houma (LA), +- Fourchon (LA), and +- Venice (LA). +Other than our Galveston facility, we lease all our offshore stockpoints. +In addition to these offshore stockpoints, we have seven land based stockpoints +that allow us to service clients in Texas, Louisiana, Oklahoma and New Mexico. +RAW MATERIALS. Our drilling fluids operations depend on the availability +of the following raw materials: +- barite, and +- bentonite. +Our completion fluids operations depend upon the availability of the +following raw materials: +- calcium chloride, +- calcium bromide, and +- zinc bromide. +We obtain these raw materials through: +- purchases made on the spot market for these materials, and +- supply contracts with producers of these raw materials. +EQUIPMENT. We own 20 trucks and 112 trailers and lease another 26 trucks. +This equipment is used to transport drilling and completion fluids and related +equipment. This minimizes our dependency upon third parties for these ancillary +services and further enhances the efficiency of our fluids operations. +CUSTOMERS. For the year 2000, we supplied drilling and completion fluids, +and related services to 182 non-affiliated customers. This compares with 128 +non-affiliated customers for 1999. During 2000, a small group of customers +accounted for approximately 30% of the revenues for our drilling and completion +fluids operations. The loss of any one or more of these customers could have a +material adverse effect upon our drilling and completion fluids operations. +As of December 31, 2000, we were providing drilling and completion fluids, +and related services for a total of 102 wells. Three of the wells were being +drilled by affiliated parties. +BARITE GRINDING FACILITY. We own and operate a barite grinding facility, +equipped with two barite grinding mills, located in Houma, Louisiana. Having the +ability to process our own barite is critical to being competitive on the Gulf +Coast and in the Gulf of Mexico since barite routinely accounts for a +substantial portion of the dollar volume for drilling fluids jobs in both of +these areas. These mills allow us to grind raw barite into the powder additive +used in producing drilling fluids. Owning these mills reduces our production +costs and our dependence upon third parties in our supply of barite. Without the +grinding mills we would be required to purchase processed barite from third +parties, including some of our competitors, which would likely result in higher +costs. +14 +15 +COMPETITION +CONTRACT DRILLING OPERATIONS. The contract drilling industry is highly +competitive. Price is generally the most important competitive factor in the +drilling industry. Other competitive factors include the availability of +drilling equipment and experienced personnel at or near the time and place +required by customers, the reputation of the drilling contractor in the drilling +industry and our relationship with existing customers. We believe that we +compete favorably with respect to all of these factors. Competition is usually +on a regional basis, although drilling rigs are mobile and can be moved from one +region to another in response to increased demand. An oversupply of drilling +rigs in any region may result. Demand for land drilling equipment is also +dependent on the exploration and development programs of oil and natural gas +companies, which are in turn influenced primarily by: +- financial condition of such companies, +- general economic conditions, +- prices of oil and natural gas, and +- domestic and foreign political considerations and policies. +It is impracticable to estimate the number of contract drilling +competitors. Some of our competitors have substantially greater resources and +longer operating histories than we have. Also, in recent years, many drilling +companies have consolidated or merged with other companies. Although this +consolidation has decreased the total number of competitors, we believe that +competition for drilling contracts will continue to be intense. +OIL AND NATURAL GAS OPERATIONS. There is substantial competition for the +acquisition of oil and natural gas leases suitable for exploration and for the +hiring of experienced personnel. Our competitors in oil and natural gas +operations include: +- major integrated oil and natural gas companies, +- numerous independent oil and natural gas companies, +- drilling and production purchase programs, and +- individual producers and operators. +Our ability to increase our holdings of oil and natural gas reserves in the +future is directly dependent upon our ability to select, acquire and develop +suitable prospects in competition with these companies. Many competitors in this +business segment have financial resources, staffs, facilities and other +resources significantly greater than ours. +DRILLING AND COMPLETION FLUIDS OPERATIONS. The drilling and completion +fluids services industry is highly competitive. Price is generally the most +important competitive factor in the industry. Other competitive factors include +the availability of chemicals and experienced personnel, the reputation of the +fluids services provider in the drilling industry and our relationship with +existing customers. +Demand for drilling and completion fluids is also dependent on the +exploration and development programs of oil and natural gas companies, which are +in turn influenced primarily by the financial condition of such companies, by: +- general economic conditions, +- prices of oil and natural gas, and +- domestic and foreign political considerations and policies. +It is impracticable to estimate the number of our drilling and completion fluids +competitors. Some of our competitors have substantially greater resources and +longer operating histories than we have. We believe that competition for +drilling contracts will continue to be intense. +15 +16 +GOVERNMENT AND ENVIRONMENTAL REGULATION +The domestic drilling of oil and natural gas wells is subject to numerous +state and federal laws, rules and regulations. State statutory provisions +relating to the drilling of oil and natural gas wells generally include +requirements as to: +- well spacing, +- waste prevention, +- production limitations, +- disposal of produced waters, +- pollution prevention and clean-up, +- obtaining drilling permits, and +- similar matters. +Within the state of Texas, where substantially all of our operations are +currently conducted, these regulations principally are enforced by the Texas +Railroad Commission. To date, we have not been required to expend significant +resources in order to satisfy applicable environmental laws and regulations. +We do not anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures associated with compliance 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 for noncompliance. Patterson has not been +fined or incurred liability for noncompliance, pollution or other environmental +damage in connection with its operations. We are not currently aware of any +environmental hazards which would materially affect our operations. +The contract drilling industry is dependent on demand for services from the +oil and natural gas exploration industry. Accordingly, the industry is affected +by: +- changing tax laws, +- price controls, and +- other laws generally related to the energy business. +Our business is affected generally by political developments and by +federal, state, foreign and local laws and regulations, which relate to the oil +and natural gas industry. The adoption of laws and regulations affecting the oil +and natural gas industry for economic, environmental and other policy reasons +could increase costs relating to drilling and production. They could have an +adverse effect on our operations. Several state and federal environmental laws +and regulations currently apply to our operations and may become more stringent +in the future. +We have utilized operating and disposal practices that were or are +currently 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 operated by us or our predecessors in interest. In addition, +some of these properties have been operated by third parties over whom we have +no control either as to such entities' treatment of hydrocarbon and other +materials or the manner in which such materials may have been disposed of or +released. +The federal Comprehensive Environmental Response Compensation and Liability +Act of 1980, 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 and comparable state +statutes govern the disposal of "hazardous wastes." Although CERCLA currently +excludes petroleum from the definition of "hazardous +16 +17 +substances," and the Resource Conservation and Recovery Act also excludes +certain classes of exploration and production wastes from regulation, such +exemptions by Congress under both CERCLA and the Resource Conservation and +Recovery Act may be deleted, limited or modified in the future. If such changes +are made to CERCLA and/or the Resource Conservation and Recovery Act, 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 +and implementing regulations govern: +- the prevention of discharges, including oil and produced water spills, +and +- liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than previous oil +pollution liability and prevention laws. It imposes strict liability for a +comprehensive and expansive list of damages from an oil spill into waters from +facilities. Liability may be imposed for oil removal costs and a variety of +public and private damages. Penalties may also be imposed for violation of +federal safety, construction and operating regulations, and for failure to +report a spill or to cooperate fully in a clean-up. +The Oil Pollution Act also expands the authority and capability of the +federal government to direct and manage oil spill clean-up and operations, and +requires operators to prepare oil spill response plans in cases where it can +reasonably be expected that substantial harm will be done to the environment by +discharges on or into navigable waters. We have spill prevention control and +countermeasure plans in place for our oil and natural gas properties in each of +the areas in which we operate and for each of the stockpoints operated by our +drilling and completion fluids business. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a +responsible party 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 and various state and +local laws impose certain air quality requirements on Patterson. Amendments to +the Clean Air Act revised the definition of "major source" such that emissions +from both wellhead and associated equipment involved in oil and natural gas +production may be added to determine if a source is a "major source." As a +consequence, more facilities may become major sources and thus would be required +to obtain operating permits. This permitting process may require capital +expenditures in order to comply with permit limits. +RISKS AND INSURANCE +Our operations are subject to the many hazards inherent in the drilling +business, including: +- blow-outs, +- cratering, +- fires, and +- explosions. +These hazards could cause: +- personal injury or death, +- suspension of drilling operations, or +- serious damage or destruction of the equipment involved and, in addition +to environmental damage, could cause substantial damage to producing +formations and surrounding areas. +17 +18 +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 +- extensive, uncontrolled fires. +In addition, we could become subject to liability for reservoir damages. The +occurrence of a significant event, including pollution or environmental damages, +could materially affect our operations and financial condition. +As a protection against operating hazards, we maintain insurance coverage +we consider to be adequate, including: +- all-risk physical damages, +- employer's liability, +- commercial general liability, and +- workers compensation insurance. +Patterson currently has: +- general liability insurance of $2.0 million per occurrence with an +aggregate of $2.0 million, and +- excess liability and umbrella coverage of up to $40.0 million per +occurrence with a $40.0 million aggregate. +Our customers generally require us to have at least $1.0 million of third party +liability coverage. Since April 1, 1992, we have carried workers' compensation +insurance, with a deductible of $100,000 per occurrence. If multiple workers' +compensation claims are filed, we could incur significant expenses, which in +turn could have a material adverse impact on our financial condition and +operations. +We believe that we are adequately insured for public liability and property +damage to others with respect to our operations. However, such insurance may not +be sufficient to protect us against liability for all consequences of: +- well disasters, +- extensive fire damage, or +- damage to the environment. +We also carry insurance to cover physical damage to or loss of our drilling +rigs. However, we do not carry insurance against loss of earnings resulting from +such damage or loss. In view of the difficulties that may be encountered in +renewing such insurance at reasonable rates, no assurance can be given that: +- we will be able to maintain the type and amount of coverage that we +consider adequate at reasonable rates, or +- any particular types of coverage will be available. +EMPLOYEES +We employed approximately 3,062 full-time persons (132 office personnel and +2,930 field personnel) at December 31, 2000. The number of drilling rig +employees will fluctuate depending upon our number of marketable drilling rigs +and the demand for contract drilling services. We consider our employee +relations to be satisfactory. None of our employees is represented by a union. +18 +19 +CORPORATE HEADQUARTERS, FIELD OFFICES AND OTHER FACILITIES +Our corporate headquarters are located in Snyder, Texas. We have a number +of small offices and yard 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 (915) 573-1104. There are a +number of improvements at our headquarters, including: +- an executive office building with approximately 16,000 square feet, +- a main shop facility with approximately 7,000 square feet used for +drilling equipment repairs and metal fabrication, +- an engine shop facility with approximately 5,000 square feet used to +completely overhaul and repair the engines used to power our drilling +rigs, and +- an open-ended metal storage facility with approximately 10,200 square +feet. +We also have small offices in: +- Austin, +- Houston, +- Midland, +- San Angelo, +- Corpus Christi, +- LaGrange, and +- Kilgore, Texas; +- Hobbs, New Mexico, +- Vernal, Utah, +- Oklahoma City, Oklahoma, +- Lafayette, Louisiana, and +- approximately 26 yard and stockpoint facilities variously located in our +areas of operations. +We own our headquarters in Snyder and both lease and own our outlying +offices and yard facilities. We do not believe that any of these outlying +offices and yard facilities are material to our operations. We lease stockpoint +facilities which are considered material to our drilling and completion fluids +operations. We believe that our existing facilities are suitable and adequate to +most of our needs. +ITEM 3. LEGAL PROCEEDINGS. +We are party to various legal proceedings arising in the normal course of +our business. We do not believe that the outcome of these proceedings will have +a material adverse effect on our financial condition. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. +None. +19 +20 +CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" +PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 +We include the following cautionary statement to take advantage of the +"safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 +for any forward-looking statement made by us, or on our behalf. The factors +identified in this cautionary statement are important factors (but not +necessarily all of the important factors) that could cause actual results to +differ materially from those expressed in any forward-looking statement made by +us, or on our behalf. Where any such forward-looking statement includes a +statement of the assumptions or bases underlying such forward-looking statement, +we caution that, while we believe such assumptions or bases to be reasonable and +make them in good faith, assumed facts or bases almost always vary from actual +results. The differences between assumed facts or bases and actual results can +be material, depending upon the circumstances. +Where, in any forward-looking statement, Patterson, or our management, +expresses an expectation or belief as to the future results, such expectation or +belief is expressed in good faith and believed to have a reasonable basis. +However, there can be no assurance that the statement of expectation or belief +will result, or be achieved or accomplished. Taking this into account, the +following are identified as important risk factors that could cause actual +results to differ materially from those expressed in any forward-looking +statement made by, or on behalf of, Patterson: +RISKS RELATED TO PATTERSON'S BUSINESS GENERALLY +PATTERSON IS DEPENDENT ON THE OIL AND NATURAL GAS INDUSTRY AND MARKET PRICES FOR +OIL AND NATURAL GAS. DECLINES IN OIL AND NATURAL GAS PRICES COULD ADVERSELY +AFFECTED OUR OPERATIONS. +Our revenue, profitability and rate of growth are substantially dependent +upon prevailing prices for oil and natural gas. In recent years, oil and natural +gas prices and, therefore, the level of drilling, exploration, development and +production, have been extremely volatile. Prices are affected by: +- market supply and demand, +- international military, political and economic conditions, and +- the ability of the Organization of Petroleum Exporting Countries, +commonly known as OPEC, to set and maintain production and prices. +All of these factors are beyond our control. Low level commodity prices +beginning in the fourth quarter of 1997 and continuing into mid-1999 materially +adversely affected our operations. We expect oil and natural gas prices to +continue to be volatile and to effect our financial condition and operations and +ability to access sources of capital. +INDUSTRY CONDITIONS FOR CONTRACT DRILLING SERVICES HAVE BEEN POOR FOR MUCH OF +THE TIME SINCE 1982. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 due to stronger oil and natural gas +prices. The increase in demand returned beginning in mid-1999 and has continued +through 2000. However, except for those periods and other occasional upturns, +the market for onshore contract drilling services has generally been depressed +since 1982, when the number of operable land drilling rigs was at record levels. +Since this time and except during the occasional upturns, there have been +substantially more drilling rigs available than necessary to meet demand in most +operational and geographic segments of the domestic drilling industry. As a +result, drilling contractors have had difficulty sustaining profit margins. +In addition to adverse effects that future declines in demand could have on +Patterson, ongoing factors which could adversely affect utilization rates and +pricing, even in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +- movement of drilling rigs from region to region, +- reactivation of land-based drilling rigs, or +- new construction of drilling rigs. +20 +21 +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 AND OTHER DRILLING EQUIPMENT OPERATIONS. +The increase since mid-1999 in domestic drilling demand and the related +increase in contract drilling activity has resulted in a shortage of drill pipe +and rig parts in the industry. This shortage has caused the price of these items +to increase significantly and has required that orders for the items be placed +well in advance of expected use. These price increases and delays in delivery +have caused us to substantially increase capital expenditures in our contract +drilling segment. Severe shortages could impair our ability to obtain the +equipment required for contract drilling operations. +THE VARIOUS BUSINESS SEGMENTS IN WHICH WE OPERATE ARE HIGHLY COMPETITIVE. +CONTRACT DRILLING BUSINESS. The inability to compete effectively in the +contract drilling industry would adversely impact our overall operations. Price +is generally the most important competitive factor. Other competitive factors +include: +- the availability of drilling equipment and experienced personnel at or +near the time and place required by customers, +- the reputation of the drilling contractor, and +- the drilling contractors' relationship with existing customers. +Competition is usually on a regional basis, although drilling rigs are mobile +and can be moved from one region to another in response to increased demand. An +oversupply of drilling rigs in any region may result. +Demand for land drilling equipment is also dependent on the exploration and +development budgets of oil and natural gas companies. These budgets are in turn +influenced primarily by: +- the financial condition of such companies, +- general economic conditions, +- prices of oil and natural gas, and +- political considerations and policies. +It is not practical to estimate the number of our contract drilling competitors. +Also, in recent years, many drilling companies have consolidated or merged with +other companies. Although this consolidation has decreased the total number of +competitors, we believe the competition for drilling services will continue to +be intense. +OIL AND NATURAL GAS EXPLORATION AND PRODUCTION BUSINESS. There is also +substantial competition for the acquisition of oil and natural gas leases +suitable for exploration and for the hiring of experienced personnel. Our +competitors in the exploration, development and production industry include: +- major integrated oil and natural gas companies, +- numerous independent oil and natural gas companies, +- drilling and production purchase programs, and +- individual producers and operators. +Our ability to increase our holdings of oil and natural gas reserves in the +future is directly dependent upon our ability to select, acquire and develop +suitable prospects in competition with those companies. Many competitors have +financial resources, staff, facilities and other resources significantly greater +than those of Patterson. +21 +22 +DRILLING AND COMPLETION FLUIDS BUSINESS. The drilling and completion +fluids services industry is highly competitive. Price is generally the most +important competitive factor in the industry. Other competitive factors include +the availability of chemicals and experienced personnel, the reputation of the +fluids services provider in the drilling industry and our relationship with +existing customers. +Demand for drilling and completion fluids is also dependent on the +exploration and development programs of oil and natural gas companies, which are +in turn influenced primarily by the financial condition of such companies, by: +- general economic conditions, +- prices of oil and natural gas, and +- political considerations and policies. +It is impracticable to estimate the number of our drilling and completion fluids +competitors. Some of our competitors have substantially greater resources and +longer operating histories than we have. We believe that competition for +drilling contracts will continue to be intense for the foreseeable future. +LABOR SHORTAGES ARE ADVERSELY AFFECTING OUR DRILLING OPERATIONS. +The increased demand for domestic contract drilling services has caused a +shortage of qualified drilling rig personnel in the industry. This increase +adversely affects our ability to attract and retain sufficient qualified +personnel to market and operate our drilling rigs. These labor shortages have +also caused wage increases, which impact our operating margins. +PATTERSON HAS BORROWINGS; FAILURE TO REPAY COULD RESULT IN FORECLOSURE ON +DRILLING RIGS. +Patterson has a $70 million credit facility with an outstanding principal +balance of $24.0 million at February 27, 2001. All of our drilling rigs and +related drilling equipment are pledged as collateral on the facility. The loan +was payable in monthly payments of interest only until February 2001, at which +time the loan converted to a term loan with a 60-month, level principal +amortization. A decline in general economic conditions in the oil and natural +gas industry could adversely affect our ability to repay the loan. Failure to +repay could, at the lender's election, result in acceleration of the maturity +date of the loan and foreclosure on the drilling assets. Additionally, the loan +agreement contains a number of covenants, including financial covenants, the +failure of which to satisfy could also cause acceleration of the maturity date +and require immediate repayment. The first principal payment of $406,972 was +made in February 2001. +CONTINUED GROWTH THROUGH RIG ACQUISITION IS NOT ASSURED. +We have increased our drilling rig fleet over the past several years +through strategic acquisitions. In February 2001, we entered into a merger +agreement with UTI Energy Corp. which, if closed, would double the number of our +drilling rigs. Although the land drilling industry has experienced significant +consolidation over the past couple of years, we believe that acquisition +opportunities are still available. However, we are likely to continue to face +intense competition from other companies for available acquisition +opportunities. +There can be no assurance that: +- we would have sufficient capital resources to complete additional +acquisitions, +- acquisitions could be completed on terms acceptable to us, or +- any completed acquisition would improve our financial condition, results +of operation, business or prospects in any material manner. +We may incur substantial indebtedness to finance future acquisitions and also +may issue equity securities or convertible securities in connection with any +such acquisitions. Additional debt service requirements could represent a +significant burden on our results of operations and financial condition and the +issuance of +22 +23 +additional equity could be dilutive to our existing stockholders. Also, +continued growth could strain our management, operations, employees and +resources. +OUR OPERATIONS ARE SUBJECT TO OPERATING HAZARDS AND UNINSURED RISKS. +Our business operations are subject to a number of risks and hazards. These +activities could cause: +- serious injury or death to persons, +- suspension of drilling operations, +- serious damage to equipment or property of others, and +- damage to producing oil and natural gas formations in adjoining areas. +Our operations could also cause environmental damage, particularly through: +- oil spills, +- gas leaks, +- discharges of toxic gasses, or +- extensive uncontrolled fires. +In addition, we could become subject to liability for oil and natural gas +reservoir damage. The occurrence of a significant event, including pollution or +environmental damage, could materially affect our operations and financial +condition. +Our insurance and contractual indemnification agreements from customers may +not be adequate to protect us against liability from all consequences of: +- well disasters, +- extensive fire damage, or +- damage to the environment. +There is no assurance that we will be able to maintain adequate insurance +in the future at rates we consider reasonable or that any particular type of +coverage will be available. We generally have been able to obtain some degree of +contractual indemnification from our customers in most of our day rate drilling +contracts against pollution and environmental damages. However, there is no +assurance that: +- we would be able to enforce the indemnification, +- the customer will be financially able in all cases to comply with its +indemnity obligations, or +- we will be able to obtain these indemnification agreements in the future. +No indemnification is typically available for turnkey contracts. While we also +maintain insurance coverage against certain environmental liabilities, including +pollution caused by sudden and accidental oil spills, we cannot assure that we +will continue to be able to secure or carry this insurance, or, if we were able +to do so, that the coverage would be adequate to cover the liabilities. +VIOLATIONS OF ENVIRONMENTAL LAWS AND REGULATIONS COULD MATERIALLY ADVERSELY +AFFECT OUR OPERATIONS. +Our operations are subject to numerous domestic laws and regulations that +relate directly or indirectly to the drilling of oil and natural gas wells, +including laws and regulations: +- controlling the discharge of materials into the environment, +- requiring removal and clean-up under certain circumstances, or otherwise, +and +- relating to the protection of the environment. +23 +24 +Laws and regulations protecting the environment have generally become more +stringent in recent years. They may in certain circumstances impose strict +liability, rendering a person liable for environmental damage without regard to +negligence or to the fault on the part of such person. Such laws and regulations +may expose us to liability for the conduct of, or conditions caused by, others, +or for our acts that were in compliance with all applicable laws at the time +such acts were performed. +SOME OF OUR CONTRACT DRILLING SERVICES ARE DONE UNDER TURNKEY CONTRACTS, WHICH +ARE FINANCIALLY RISKY. +A portion of our contract drilling is done under turnkey contracts, which +involve substantial risks. Under turnkey drilling contracts, we contract to +drill a well to a certain depth under specified conditions for a fixed price. +The risks to us under these types of drilling contracts are substantially +greater than on a well drilled on a daywork basis. This is due to the assumption +by us in turnkey contracts of most of the risks associated with the drilling +operations generally assumed by the operator of the well in a daywork contract, +including: +- risk of blowout, +- machinery breakdowns, and +- abnormal drilling conditions. +Accordingly, if severe drilling problems are encountered in drilling wells under +a turnkey contract, we could suffer substantial losses associated with that +contract. Generally, the weaker the demand for our drilling services, the higher +the percentage of our turnkey contracts. For each of the years in the three-year +period ended December 31, 2000, the percentage of our contract drilling revenues +attributable to turnkey contracts was 12%, 20.0% and 8.0%, respectively. +ESTIMATES OF OUR OIL AND NATURAL GAS RESERVES ARE UNCERTAIN. +Estimates of our proved developed reserves and future net revenues are +based on engineering reports prepared by an independent petroleum engineer. +These reports are based upon a review of production of histories and other +geologic, economic, ownership and engineering data provided by Patterson. These +estimates are based on several assumptions that the SEC requires oil and natural +gas companies to use, including, for example, constant oil and natural gas +prices. The estimates are inherently imprecise indications of future net +revenues. Actual future production, revenues, taxes, production costs and +development costs may vary substantially from those assumed in the estimates. +Any significant variance could materially affect the estimates. In addition, our +reserves might be subject to upward or downward adjustment based on: +- future production, +- results of future exploration and development, +- prevailing oil and natural gas prices, and +- other factors. +24 +25 +RISKS RELATED TO PATTERSON'S OPERATIONS +THE LOSS OF SERVICES OF KEY OFFICERS COULD HURT OUR OPERATIONS. +We are highly dependent on our executive officers and key employees. The +unexpected loss of the services of any of these individuals, particularly Cloyce +A. Talbott or A. Glenn Patterson, Chief Executive Officer and President, +respectively, could have a detrimental affect on Patterson. We have no +employment agreements with any of our executive officers. We maintain key man +life insurance on the lives of Messrs. Talbott and Patterson in the amount of $3 +million each. +ANTI-TAKEOVER MEASURES IN OUR CHARTER DOCUMENTS AND UNDER STATE LAW COULD +DISCOURAGE AN ACQUISITION OF PATTERSON AND THEREBY AFFECT THE RELATED PURCHASE +PRICE. +Patterson, as a Delaware corporation, is 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 of Patterson may find +it more difficult or be discouraged from attempting to effect an acquisition +transaction with us. This may deprive holders of our securities of certain +opportunities to sell or otherwise dispose of the securities at above-market +prices pursuant to any such transactions. +WE HAVE PAID NO DIVIDENDS ON OUR COMMON STOCK AND HAVE NO PLANS TO PAY DIVIDENDS +IN THE FORESEEABLE FUTURE. +We have not declared or paid cash dividends on our common shares in the +past. We do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. The terms of our existing credit facility prohibit +payment of dividends by us without the prior written consent of the lenders. +PARTICIPATION BY PATTERSON DIRECTORS AND OFFICERS IN OIL AND NATURAL GAS +PROSPECTS COULD CREATE CONFLICTS OF INTEREST. +Certain of our directors and executive officers and their respective +affiliates have participated, from time to time, in oil and natural gas +prospects and properties in which we have interest. These participations may +continue in the future. Conflicts of interest may arise between such persons and +Patterson as to the advisability of conducting drilling and recompletion +activities on these properties. Of the 164 wells we operated at the end of year +2000, our directors, officers and/or their respective affiliates were working +interest owners in approximately 127 wells. +OUR BOARD MAY ISSUE PREFERRED STOCK WITH RIGHTS AND PREFERENCES ADVERSE TO +COMMON STOCK. +We have a class of authorized preferred stock. Our board of directors, +without stockholder approval, may issue shares of the preferred stock with +rights and preferences adverse to the voting power or other rights of the +holders of common stock. We have not issued any preferred shares. However, as of +December 31, 2000, an aggregate of 374,773 shares of our preferred stock had +been reserved for issuance upon exercise of the rights issued under our +stockholders rights plan. +25 +26 +PART II +ITEM 5. MARKET FOR OUR COMMON SHARES AND RELATED STOCKHOLDER MATTERS. +Our common stock, par value $0.01 per share is publicly traded on the +Nasdaq National Market and is quoted under the symbol "PTEN." +The following table sets forth the high and low sales prices of our common +shares for the periods indicated: +HIGH LOW +---- --- +1999: +First quarter............................................... $ 6.06 $ 2.75 +Second quarter.............................................. 10.81 4.38 +Third quarter............................................... 16.31 8.38 +Fourth quarter.............................................. 15.94 10.00 +2000: +First quarter............................................... $ 31.88 $ 11.63 +Second quarter.............................................. 32.25 19.63 +Third quarter............................................... 35.94 21.44 +Fourth quarter.............................................. 39.50 22.50 +As of February 20, 2001, there were approximately 332 holders of record +(approximately 8,357 beneficial holders) of our common shares. +We have not declared or paid cash dividends on our common shares in the +past and do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. Instead, we intend to retain our earnings to support +the operations and growth of our business. Any future cash dividends would +depend on future earnings, capital requirements, financial condition and other +factors deemed relevant by the board of directors. In addition, the terms of our +existing credit facility prohibit payment of dividends without the prior written +consent of the lenders. +During 2000, we issued a total of 1,203,000 common shares and three-year +warrants to acquire 127,000 common shares that were not registered under the +Securities Act of 1933, as amended. The shares were issued in two separate +transactions as follows: +- During March 2000, we issued a total of 53,000 common shares valued at +$29.0625 per share as partial consideration for the acquisition of four +drilling rigs and related equipment from an unrelated entity. +- The remaining 1,150,000 common shares and the warrants to acquire 127,000 +common shares we issued as consideration for the acquisition of eight +drilling rigs and related equipment acquired during June 2000 from an +unrelated entity. The common shares were valued at $18.00 per share, the +market price of the shares on the date of the transaction. The warrants +were valued at $900,000 using a Black-Scholes model. +Each of the shares and warrant shares, subsequent to their respective +issuances, have been registered for resale with the SEC. +No underwriter was involved in either of the transactions and no sales +commissions, fees or similar compensation were paid to any person in connection +with the issuance of the shares. We believe that the issuance of the shares in +each instance was exempt from the registration requirements of Section 5 of the +Securities Act by virtue of Section 4(2) of the Securities Act and/or under Rule +506 of Regulation D promulgated by the SEC thereunder. +26 +27 +ITEM 6. SELECTED FINANCIAL DATA. +The selected consolidated financial data of Patterson as of December 31, +1996, 1997, 1998, 1999 and 2000 and for each of the five years then ended should +be read in conjunction with "Management's Discussion and Analysis of Financial +Condition and Results of Operations" and the Consolidated Financial Statements +and related Notes thereto, included as Items 7 and 8, respectively, of this +document. +YEAR ENDED DECEMBER 31, +------------------------------------------------------------- +1996 1997 1998 1999 2000 +---- ---- ---- ---- ---- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +(UNAUDITED) +INCOME STATEMENT DATA: +Operating revenues: +Drilling..................... $ 73,590 $ 178,332 $ 165,997 $ 131,287 $ 260,233 +Oil and natural gas.......... 10,118 12,445 7,170 8,563 15,615 +Drilling completion fluids... -- -- 13,397 11,686 32,053 +--------- ---------- ---------- ---------- ---------- +Total................ 83,708 190,777 186,564 151,536 307,901 +--------- ---------- ---------- ---------- ---------- +Operating costs and expenses: +Drilling..................... 59,564 128,416 128,838 113,569 190,234 +Oil and natural gas.......... 3,465 4,402 3,676 2,500 4,872 +Drilling and completion +fluids.................... -- -- 10,205 9,864 26,545 +Impairment of proved oil and +natural gas properties.... 549 355 3,816 275 -- +Depreciation, depletion and +amortization.............. 9,960 17,497 28,091 28,156 33,133 +General and administrative... 5,416 6,786 9,313 7,299 11,394 +--------- ---------- ---------- ---------- ---------- +Total................ 78,954 157,456 183,939 161,663 266,178 +--------- ---------- ---------- ---------- ---------- +Operating income (loss)........ 4,754 33,321 2,625 (10,127) 41,723 +--------- ---------- ---------- ---------- ---------- +Other income (expense)......... (2,737) 1,787 (2,857) (3,341) (3,724) +--------- ---------- ---------- ---------- ---------- +Income (loss) before income +taxes........................ 2,017 35,108 (232) (13,468) 37,999 +Income tax expense (benefit)... (2,254) 12,866 93 (4,341) 14,244 +--------- ---------- ---------- ---------- ---------- +Net income (loss).............. $ 4,271 $ 22,242 $ (325) $ (9,127) $ 23,755 +========= ========== ========== ========== ========== +Net income (loss) per common +share: +Basic........................ $ 0.22 $ 0.78 $ ( 0.01) $ ( 0.28) $ 0.69 +========= ========== ========== ========== ========== +Diluted...................... $ 0.21 $ 0.75 $ ( 0.01) $ ( 0.28) $ 0.66 +========= ========== ========== ========== ========== +Weighted average number of +common shares outstanding: +Basic........................ 19,167 28,492 31,645 32,499 34,347 +========= ========== ========== ========== ========== +Diluted...................... 20,086 29,505 31,645 32,499 35,753 +========= ========== ========== ========== ========== +BALANCE SHEET DATA: +Total assets................... $ 87,913 $ 203,200 $ 236,605 $ 236,257 $ 410,586 +Notes payable.................. 25,849 23,250 55,714 50,000 24,416 +Stockholders' equity........... 43,482 146,932 156,852 152,788 302,806 +27 +28 +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. These statements include, without limitation, statements relating to: +- liquidity, +- financing of operations, +- continued volatility of oil and natural gas prices, +- source and sufficiency of funds required for capital needs and additional +rig acquisitions (if further opportunities arise), +- future utilization of net operating loss carryforwards, +- impact of inflation on our financial position and on our earnings per +share, and +- other such matters. +The words "believes," "budgeted," "expects" or "estimates" and similar +expressions identify forward-looking statements. We do not undertake to update, +revise or correct any of the forward-looking information. Readers are cautioned +that such forward-looking statements should be read in conjunction with our +disclosures under the heading: "Cautionary Statement for Purposes of the 'Safe +Harbor' Provisions of the Private Securities Litigation Reform Act of 1995" +beginning on page 20. +LIQUIDITY AND CAPITAL RESOURCES +As of December 31, 2000, we had working capital of approximately $110.9 +million including cash and cash equivalents of approximately $59.4 million as +compared to working capital of approximately $27.0 million including cash and +cash equivalents of approximately $8.8 million as of December 31, 1999. For the +twelve months ended December 31, 2000, our various sources of cash flow were: +- $49.1 million derived from operations, +- $98.8 million generated from the public offering of 3,000,000 shares of +our common stock, +- $3.2 million from the exercise of stock options and warrants, +- $14.4 million of proceeds provided by our credit facility with +Transamerica Equipment Financial Services Corporation, +- $1.1 million from the sale of certain property and equipment, and +- $630,000 from other non-operating activities. +Correspondingly, a portion of the funds, as discussed above, were used by +us during the year as follows: +- $40.0 million to repay, prior to its respective maturity, long-term +indebtedness then outstanding with Transamerica, +- $17.8 million as partial consideration in the acquisitions of WEK +Drilling Co., Inc. and certain assets of Ambar, Inc., +- $57.2 million to make necessary repair and maintenance expenditures for +the betterment and refurbishment of both the marketable and non-operable +drilling rigs, as well as the acquisition and procurement of drilling +equipment, including drill pipe, to fund leasehold acquisition, +exploration and development of oil and natural gas properties and to fund +capital expenditures for our drilling and completion fluids segment, and +- $1.65 million to repurchase 300,000 shares of our own common stock +originally issued in the acquisition of the assets of Padre Industries, +Inc. +28 +29 +During 2000, we entered into three separate transactions whereby we +increased our land-based drilling rig fleet to 131, an increase of 12 rigs from +a year ago, and we further expanded our drilling fluids operations with the +addition of drilling and completion fluids operations in Louisiana, the Gulf +Coast areas of South Texas and the Gulf of Mexico. During January 2001, we added +an additional 21 drilling rigs (of which 14 were marketable) to our total rig +fleet. A brief description of each the transactions follows: +- On March 31, 2000, we acquired 100% of the outstanding stock of WEK +Drilling Company, Inc., a privately held, non-affiliated drilling company +with its principal operations in Southeast New Mexico, for an aggregate +purchase price of $6.8 million. The acquired assets included four +operable contract drilling rigs and other related equipment and working +capital of approximately $1.2 million. Three of the rigs have depth +capacities greater than 12,000 feet with the other rig having a depth +rating of 10,500 feet. We funded the acquisition using $5.66 million of +proceeds from our credit facility with Transamerica and 53,000 shares of +our common stock valued at $29.0625 per share. Certain assets, unrelated +to the contract drilling business, were sold back to one of the previous +owners for a cash payment of $1.0 million. +- On June 2, 2000, we consummated the acquisition of High Valley Drilling, +Inc. The assets consisted of eight non-operable drilling rigs and other +related equipment. The drilling rigs, when completely refurbished, will +have depth capacities equal to or exceeding 15,000 feet with three of the +rigs having a depth rating of 25,000 feet. Consideration for the +acquisition included 1,150,000 restricted shares of our common stock and +three-year warrants to acquire an additional 127,000 shares at an +exercise price of $22.00 per share. The common stock issued in connection +with the acquisition was recorded at $18.00 per share which represents +the market price of the stock on the day the acquisition was announced +and the warrants were valued at $900,000. During 2000, we expended +approximately $11.5 million refurbishing the High Valley rigs. Four of +the rigs were placed into operation by the end of December 2000 with two +additional rigs placed into service during February 2001. We anticipate +the remaining rigs to be placed into service by the end of June 2001 with +further capital expenditures not to exceed $2.5 million per rig, +including drill pipe. +- On October 3, 2000, we completed the acquisition of the drilling and +completion fluids division of Ambar, Inc., a non-affiliated entity with +its principal operations in the Louisiana and Texas Gulf Coasts and the +Gulf of Mexico. We acquired working capital of approximately $7.8 million +(current assets of $18.2 million and current liabilities of $10.4 +million), fixed assets with a fair market value of $15.7 million and +other trademarks and intellectual property specific to the division's +operations. Cash of $12.4 million was paid as consideration for the +purchase which included $680,000 of direct costs incurred related to the +transaction. +- On January 5, 2001, we completed the acquisition of Jones Drilling +Corporation and the assets of three related entities, Henderson Welding, +Inc., L.E.J. Truck and Crane, Inc., and L.E. Jones Drilling Company. All +four companies were based in Duncan, Oklahoma. The assets acquired as a +part of these transactions consisted of 21 contract drilling rigs (14 of +which were marketable), a fleet of rig moving trucks, drilling facilities +and shops and equipment yards located in Duncan, Oklahoma, and +Bridgeport, Texas. The drilling rigs range from 450 to 1,000 horsepower +with 12 rigs having a drilling capacity of 12,000 feet and greater, with +four of those rigs capable of drilling to depths greater than 15,000 +feet. The purchase price consisted of 810,070 shares of our common stock +valued at $26.8125 per share and $10.9 million cash, net of certain +working capital adjustments. +On September 14, 2000, we completed a public offering of 3 million shares +of our common stock at a public price of $34.50 per share. An underwriting +discount of $1.50 was paid, for a net price of $33.00 per share. Net proceeds +from the offering totaled approximately $98.8 million. Certain of the proceeds +were used to reduce, prior to maturity, outstanding indebtedness with +Transamerica from $64.4 million to $24.4 million, as well as a prepayment +penalty of $200,000. This penalty is included in interest expense at December +31, 2000, as we consider the amount immaterial for extraordinary treatment. +On July 20, 2000, we executed an amendment to our existing credit facility +with Transamerica, increasing the facility from $60.0 million to $70.0 million. +During 2000, we borrowed an additional $14.4 million under +29 +30 +the facility, increasing our total outstanding indebtedness under the agreement +to $64.4 million. The terms of the facility provided that the credit facility +would convert to a term note during 2000 with a 60-month, level principal +amortization to begin in February 2001. As previously discussed, using net +proceeds from the public offering we prepaid $40.0 million on the outstanding +balance and have began principal amortization in February 2001 as required by +the underlying agreement. +We believe that the current level of cash and short-term investments, +together with cash generated from operations should be sufficient to meet our +immediate capital needs. From time to time, acquisition opportunities are +reviewed relating to our business. The timing, size or success of any +acquisition and the associated capital commitments are unpredictable. Should +further opportunities for growth requiring capital arise, we believe we would be +able to satisfy these needs through a combination of working capital, cash +generated from operations, and either debt or equity financing. However, there +can be no assurance that such capital would be available. +RESULTS OF OPERATIONS +COMPARISON OF THE YEARS ENDED DECEMBER 31, 2000 AND 1999 +For the year ended December 31, 2000, contract drilling revenues were +$260.2 million as compared to $131.3 million for the same period in 1999, an +increase of approximately 98%. Average rig utilization was 74% on an average of +119 rigs available for service for the year ended December 31, 2000, as compared +to 45% on an average of 114 rigs available for service for the twelve months +ended December 31, 1999. Direct drilling costs were $190.2 million or 73% of +drilling revenues for the year ended December 31, 2000, while direct drilling +costs were $113.6 million or 87% of related drilling revenues for 1999. General +and administrative expense for the contract drilling operations was +approximately $5.3 million for the year ended December 31, 2000, as compared to +approximately $4.1 million in 1999. The increase in general and administrative +expense was largely attributable to an increase in administrative personnel +needed to support the increase in the number of rigs marketed during the year +and the increased utilization of our rig fleet. Depreciation and amortization +expense for the contract drilling segment increased from $24.4 million for the +year ended December 31, 1999, to approximately $28.0 million for the same +twelve-month period in 2000. For the twelve months ended December 31, 2000, +operating income from contract drilling operations was approximately $36.9 +million as compared to an operating loss of approximately $10.3 million in 1999. +The increase in the contract drilling segment's operating results was reflective +of 12 additional rigs acquired during the year, increased pricing of our +contract services caused by significant improvements in commodity prices, and +the resulting 64% increase in our average rig utilization rate. Notwithstanding +the recent improvement in oil and natural gas prices, there can be no assurance +that the demand for contract drilling services will increase proportionally with +the current higher commodity prices or of the duration of the higher commodity +prices. +Oil and natural gas sales revenues were approximately $13.6 million for the +year ended December 31, 2000, as compared to approximately $6.8 million in 1999. +The volumes of oil and natural gas sold increased by approximately 20% in 2000, +as compared to fiscal year 1999. The average price per Bbl of crude oil received +in 2000 was $29.99, as compared to $18.08 in 1999, and the average price per Mcf +of natural gas was $3.87 in 2000, as compared to $2.22 in 1999. Lease operating +and production costs were $6.41 per BOE in 2000, compared to $4.08 per BOE in +1999. General and administrative expense for the oil and natural gas segment was +approximately $1.5 million and $1.2 million for the years ended December 31, +2000 and 1999, respectively. Exploration costs were approximately $663,000 and +$611,000 for the years ended December 31, 2000 and 1999, respectively. +Depreciation and depletion expense was approximately $3.6 million in 2000, as +compared to approximately $2.7 million in 1999. The increase in depreciation and +depletion expense was the result of increased production during 2000 due to +significantly improved commodity prices. We impaired certain of our oil and +natural gas properties by $275,000 during 1999. No impairment expense was +incurred in 2000. Other revenues generated by the oil and natural gas segment, +consisting primarily of fees generated from lease operating activities, were +approximately $2.0 million and $1.6 million for the years ended December 31, +2000 and 1999, respectively. For the year ended December 31, 2000, the oil and +natural gas segment generated income from operations of approximately $5.6 +million as compared to income of approximately $1.9 million +30 +31 +for the year ended December 31, 1999. The fluctuation in the segment's operating +results was primarily attributable to the increase in the underlying commodity +prices as discussed above. +Operating revenues from our drilling and completion fluid services were +approximately $32.1 million and $11.7 million for the twelve months ended +December 31, 2000 and 1999, respectively. Operating costs incurred by the +drilling and completion fluids segment were approximately $26.5 million in 2000 +as compared to costs of approximately $9.9 million in 1999. For the twelve +months ended December 31, 2000, depreciation and amortization expense was $1.5 +million as compared to approximately $1.1 million in 1999. General and +administrative expense for the drilling and completion fluids segment was +approximately $4.6 million and $2.0 million for the twelve months ended December +31, 2000 and 1999, respectively. The increases noted above on each of the items +discussed were primarily attributable to the addition of the fluids division of +Ambar, Inc. during October 2000. For the twelve months ended December 31, 2000, +the drilling fluids segment generated a net loss from operations of +approximately $550,000 as compared to a net operating loss of approximately $1.4 +million for the comparative twelve month period in 1999. The improvement in +operations was consistent with the rise in the segment's operating revenues and +expenses and resulting increase in operating margin as discussed above and +reflective of the improvements in the industry's economic conditions. +For the year ended December 31, 2000, we incurred interest expense of +approximately $5.0 million as compared to $4.1 million in 1999 and earned +interest income of approximately $999,000 and $445,000 in 2000 and 1999, +respectively. In 2000, we recognized a net gain on the sale of property and +equipment of $194,000 as compared to approximately $129,000 in 1999. +COMPARISON OF THE YEARS ENDED DECEMBER 31, 1999 AND 1998 +For the year ended December 31, 1999, contract drilling revenues were +approximately $131.3 million as compared to $166.0 million for the same period +in 1998; a decrease of approximately 21%. Average rig utilization was 45% on an +average of 114 rigs available for service for the year ended December 31, 1999 +as compared to 54% on an average of 106 rigs available for service for the +twelve months ended December 31, 1998. Direct drilling costs were $113.6 million +or 87% of drilling revenues for the year ended December 31, 1999; while direct +drilling costs were $128.8 million or 78% of related drilling revenues for 1998. +General and administrative expense for the contract drilling operations was +approximately $4.1 million for the year ended December 31, 1999 as compared to +approximately $6.1 million in 1998. The decrease in general and administrative +expense was largely attributable to the our decision to close our administrative +offices in Dallas, Abilene and Wichita Falls, Texas. +Additionally, we imposed a company-wide compensation reduction and certain +layoffs during January and February 1999 in an effort to reduce overhead costs +in response to the significantly weakened economic conditions of the industry. +Depreciation and amortization expense for the contract drilling segment +increased from $22.4 million for the year ended December 31, 1998 to +approximately $24.4 million for the same twelve-month period in 1999. +For the twelve months ended December 31, 1999, operating loss from our +contract drilling operations was approximately $10.3 million as compared to +income of approximately $9.3 million in 1998. The decline in the contract +drilling segment's operating results was reflective of reduced pricing in our +contract services caused by significantly weakened commodity prices, +particularly for crude oil throughout fiscal year 1998 and the initial months of +1999, and the resulting 17% decrease in our utilization rate. +Oil and natural gas sales revenues were approximately $6.8 million for the +year ended December 31, 1999, as compared to approximately $5.6 million in 1998. +The volume of oil and natural gas sold by us decreased by approximately 11% in +1999, as compared to fiscal year 1998. The average price per Bbl of crude oil +received by us was $18.08 in 1999, as compared to $12.16 in 1998, and the +average price per Mcf of natural gas was $2.22 in 1999, as compared to $1.93 in +1998. Lease operating and production costs were $4.08 per BOE in both 1998 and +1999. General and administrative expense for the oil and natural gas segment was +approximately $1.2 million and $1.3 million for the years ended December 31, +1999 and 1998, respectively. Exploration costs were approximately $611,000 and +$669,000 for the years ended December 31, 1999 and 1998, respectively. +Depreciation and depletion expense was approximately $2.7 million in 1999, as +compared +31 +32 +to approximately $4.8 million in 1998. The decrease in depreciation and +depletion expense was reflective of the substantial increase in the market price +received for crude oil in December 31, 1999 versus December 31, 1998 which +resulted in increases in reserve quantities and a related reduction of the unit +of production rates. Specifically, the market price was $11.16 per barrel at +December 31, 1998 and $24.90 per barrel at December 31, 1999, an increase of +approximately 123%. +During 1998, primarily as a result of the industry's significantly reduced +commodity prices at December 31, 1998, we impaired certain of oil and natural +gas properties by $3.8 million. Comparatively, we incurred impairment expense of +approximately $275,000 in 1999. Other revenues generated by the oil and natural +gas segment, consisting primarily of fees generated from lease operating +activities, were approximately $1.6 million and $1.5 million for the years ended +December 31, 1999 and 1998, respectively. For the year ended December 31, 1999, +the oil and natural gas segment generated income from operations of +approximately $1.9 million as compared to a loss of approximately $6.2 million +for the year ended December 31, 1998. The fluctuation in the segment's operating +results was primarily attributable to the increase in the underlying commodity +prices as discussed above. +Operating revenues from our drilling fluid services were approximately +$11.7 million and $13.4 million for the twelve months ended December 31, 1999 +and 1998, respectively. Operating costs incurred by the drilling fluids segment +were approximately $9.9 million in 1999 as compared to costs of approximately +$10.2 million in 1998. For the twelve months ended December 31, 1999, +depreciation and amortization expense was $1.1 million as compared to +approximately $895,000 in 1998. General and administrative expense for the +drilling fluids segment was approximately $2.0 million and $1.9 million for the +twelve months ended December 31, 1999 and 1998, respectively. This increase was +partially due to the addition of the administrative office in Corpus Christi, +Texas, acquired during September 1998 with our purchase of Tejas Drilling +Fluids, Inc. For the twelve months ended December 31, 1999, the drilling fluids +segment generated a net loss from operations of approximately $1.4 million as +compared to net operating income of approximately $360,000 for the comparative +twelve month period in 1998. The net loss from operations was consistent with +the decline in the segment's operating revenues and expenses as discussed above +and reflective of the deterioration in the industry's economic conditions. +For the year ended December 31, 1999, we incurred interest expense of +approximately $4.1 million as compared to $4.5 million in 1998 and earned +interest income of approximately $445,000 and $767,000 in 1999 and 1998, +respectively. In 1999, we recognized a net gain on the sale of property and +equipment of $129,000 as compared to approximately $636,000 in 1998. +INCOME TAXES +YEAR ENDED DECEMBER 31, +------------------------- +1998 1999 2000 +---- ---- ---- +Income tax provision (benefit)............................ $ 93 $(4,341) $14,244 +Effective tax rate........................................ 40.1% (32.2%) 37.5% +We recognized income tax benefit of $4.3 million for the year ended +December 31, 1999, resulting from losses from operations. We recognized income +tax expense of $14.2 million for the year ended December 31, 2000, even though +minimal cash taxes were incurred as a result of utilization of income tax +benefits recognized in prior years. The federal statutory tax rate, used in the +provision, increased by 1% to 35% for the year ended December 31, 2000. The +state effective tax rate, used in the provision, increased to 1% for the year +ended December 31, 2000. +For tax purposes, we had available, at December 31, 2000, federal net +operating loss carryforwards of approximately $16.3 million, which will expire +in the year 2019 if unused. We also had available at December 31, 2000, $1.6 +million of alternative minimum tax credits, which may be carried forward +indefinitely. +During the year ended December 31, 1996, we began recording non-cash +Federal deferred income taxes based primarily on the relationship between the +amount of our unused Federal NOL carryforwards and the +32 +33 +temporary differences between the book basis and tax basis in our assets. +Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. As a result of fully +recognizing the benefit of our deferred income taxes, we will incur deferred +income tax expense as these benefits are utilized. We incurred a deferred income +tax expense of approximately $15.9 million for the year ended December 31, 2000 +and a deferred income tax benefit of approximately $7.1 million for the year +ended December 31, 1999. +VOLATILITY OF OIL AND NATURAL GAS PRICES +Our revenue, profitability and future rate of growth are substantially +dependent upon prevailing prices for oil and natural gas, with respect to our +contract drilling, oil and natural gas and drilling and completion fluids +segments. Historically, oil and natural gas prices and markets have been +extremely volatile. Prices are affected by market supply and demand factors as +well as actions of state and local agencies, the United States and foreign +governments and international cartels. All of these are beyond our control. Any +significant or extended decline in oil and/or natural gas prices will have a +material adverse effect on our financial condition and results of operations, as +evidenced by our performance. Low level commodity prices beginning in the fourth +quarter of 1997 and continuing into mid-1999 adversely impacted our operations. +Although there has been significant improvement in oil and natural gas prices +since mid-1999, we expect oil and natural gas prices to continue to be volatile +and therefore to affect the financial condition and operations of Patterson and +its ability to access capital sources. +IMPACT OF INFLATION +We believe that inflation will not have a significant near-term impact on +our financial position. +RECENTLY-ISSUED ACCOUNTING STANDARDS +The Company adopted Statement of Financial Accounting Standards No. 133, as +amended, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS +No. 133") on January 1, 2001. SFAS No. 133 establishes accounting and reporting +standards for derivatives or instruments and for hedging activities. It requires +enterprises to recognize all derivatives as either assets or liabilities in the +balance sheet and measure those instruments at fair value. The requisite +accounting for changes in the fair value of a derivative depends on the intended +use of the derivative and the resulting designation. The Company was not +required to record any transitional adjustment upon the adoption of SFAS No. +133. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +We have exposure to market risk associated with the floating rate portion +of the interest charged on the $24.4 million outstanding under our credit +facility with Transamerica Equipment Financial Services Corporation. The credit +facility, which matures on January 1, 2006, bears interest at LIBOR plus 3.10% +to 3.51%. Our exposure to interest rate risk due to changes in LIBOR is not +expected to be material and at December 31, 2000, the fair value of the +obligation approximates our related carrying value because the obligation bears +interest at the current market rate. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +Financial Statements are filed as a part of this report at the end of Part +IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and +are incorporated herein by this reference. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE. +None. +33 +34 +PART III +The information required by Part III is omitted from this report because +Patterson will file a definitive proxy statement pursuant to Regulation 14A of +the Securities Exchange Act of 1934 no later than 120 days after the end of the +fiscal year covered by this document and certain information included therein is +incorporated herein by reference. +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 11. EXECUTIVE COMPENSATION. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. +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. +34 +35 +PART IV +ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. +(a)(1) Financial Statements. +See Index to Consolidated Financial Statements on page F-1 of this report. +(a)(2) Financial Statement Schedule. +Schedule II -- Valuation and qualifying accounts is filed herewith on page +S-1. +All other financial statement schedules have been omitted because they are +not applicable or the information required therein is included elsewhere in the +financial statements or notes thereto. +(a)(3) Exhibits. +The following exhibits are filed herewith or incorporated by reference +herein. +2.1 Plan and Agreement of Merger dated October 14, 1993, between +Patterson Energy, Inc., a Texas corporation, and Patterson +Energy, Inc., a Delaware corporation, together with related +Certificates of Merger.(1) +2.2 Agreement and Plan of Merger, dated April 22, 1996 among +Patterson Energy, Inc., Patterson Drilling Company and +Tucker Drilling Company, Inc.(2) +2.2.1 Amendment to Agreement and Plan of Merger, dated May 16, +1996 among Patterson Energy, Inc., Patterson Drilling +Company and Tucker Drilling Company, Inc.(3) +2.3 Stock Purchase Agreement, dated January 5, 1998, among +Patterson Energy, Inc., Spencer D. Armour, III. And Richard +G. Price.(16) +2.4 Stock Purchase Agreement, dated September 17, 1998, among +Lone Star Mud, Inc. and Mark Campbell (shareholder of Tejas +Drilling Fluids, Inc.).(4) +2.5 Asset Purchase Agreement dated as of September 30, 2000 +between Ambar Drilling Fluids LP, LLLP and Ambar, Inc.(5) +2.6 Agreement and Plan of Merger, dated February 4, 2001, by and +between UTI Energy Corp. and Patterson Energy, Inc. +Disclosure schedules for each of the parties to the merger +agreement setting forth exceptions or other information +relating to their respective representations and warrants in +the agreement have not been filed with this exhibit. They +will, however, be made available supplementally to the SEC +upon request.(6) +3.1 Restated Certificate of Incorporation.(7) +3.1.1 Certificate of Amendment to the Certificate of +Incorporation.(8) +3.2 Bylaws.(1) +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(15) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson Energy, Inc. regarding authorized Common Stock and +Preferred Stock.(9) +10.1 Loan and Security Agreement dated December 21, 1999 among +Patterson Drilling Company and Transamerica Equipment +Financial Services Corporation.(17) +10.1.1 Promissory Note dated December 21, 1999 between Patterson +Drilling Company and Transamerica Equipment Financial +Services Corporation.(17) +10.1.2 Corporate Guarantees of Lone Star Mud, Inc. and Patterson +Energy, Inc.(17) +10.2 Aircraft Lease, dated December 20, 2000, (effective January +1, 2001) between Talbott Aviation, Inc. and Patterson +Energy, Inc. +35 +36 +10.3 Participation Agreement, dated October 19, 1994, between Patterson Petroleum Trading +Company, Inc. and BHT Marketing, Inc.(10) +10.3.1 Participation Agreement dated October 24, 1995, between Patterson Petroleum Trading +Company, Inc. and BHT Marketing, Inc.(11) +10.4 Crude Oil Purchase Contract, dated October 19, 1994, between Patterson Petroleum, Inc. and +BHT Marketing, Inc.(10) +10.4.1 Crude Oil Purchase Contract, dated October 24, 1995, between Patterson Petroleum, Inc. and +BHT Marketing, Inc.(11) +10.5 Patterson Energy, Inc. 1993 Stock Incentive Plan, as amended.(12) +10.6 Patterson Energy, Inc. Non-Employee Directors' Stock Option Plan, as amended.(13) +10.7 Model Form Operating Agreement.(14) +10.8 Form of Drilling Bid Proposal and Footage Drilling Contract.(14) +10.9 Form of Turnkey Drilling Agreement.(14) +21.1 Subsidiaries of the registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers LLP. +23.2 Consent of Independent Petroleum Engineer -- M. Brian Wallace, P.E. +--------------- +(1) Incorporated herein by reference to Item 27, "Exhibits" to Amendment No. 2 +to Registration Statement on Form SB-2 (File No. 33-68058-FW); filed +October 28, 1993. +(2) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated April 22, 1996 and filed on April 30, 1996. +(3) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated May 16, 1996 and filed on May 22, 1996. +(4) Incorporated by reference to Item 14, "Financial Statements Schedules and +Reports on Form 8-K" to Form 10-K for the year ended December 31, 1998. +(5) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated October 3, 2000 and filed on November 6, 2000. +(6) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated February 4, 2001 and filed February 16, 2001. +(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 1996; filed +August 12, 1996. +(8) Incorporated herein by reference to Item 6. "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 1997; filed +August 14, 1997. +(9) Incorporated herein by reference to Item 16, "Exhibits" to Registration +Statement on Form S-3 filed on December 18, 1996. +(10) Incorporated herein by reference to Item 27, "Exhibits" to Post Effective +Amendment No. 1 to Registration Statement on Form SB-2 (File No. +33-68058-FW); filed on June 21, 1995. +(11) Incorporated by reference to Item 13, "Exhibits and Reports on Form 8-K" to +Form 10-KSB for the year ended December 31, 1995. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 333-47917); filed March 13, 1998. +(13) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471); filed November 4, 1997. +(14) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW); filed on August 30, 1993. +36 +37 +(15) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on Form 8-A filed on January 14, 1997. +(16) Incorporated herein by reference to Item 16, "Exhibits" to Registration +Statement on Form S-3 filed January 5, 1998. +(17) Incorporated by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Form 10-K for the year ended December +31, 1999. +(b) Reports on Form 8-K. +(1) Report dated November 15, 2000 announcing execution of a letter of intent to +acquire twenty-one drilling rigs from Jones Drilling Corporation; filed +December 1, 2000. +(2) Report dated November 20, 2000 announcing the Company's addition of two +members to Patterson's board of directors; filed December 1, 2000. +(3) Report dated October 3, 2000 announcing Patterson's acquisition of the +drilling and completion fluids services of Ambar, Inc.; filed November 6, +2000. +37 +38 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +PAGE +---- +REPORT OF INDEPENDENT ACCOUNTANTS......................... F-2 +CONSOLIDATED FINANCIAL STATEMENTS: +CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 1999 AND +2000.................................................. F-3 +CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS +ENDED DECEMBER 31, 1998, 1999 AND 2000................ F-4 +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE +YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000.......... F-5 +CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS +ENDED DECEMBER 31, 1998, 1999 AND 2000................ F-6 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS............. F-8 +F-1 +39 +REPORT OF INDEPENDENT ACCOUNTANTS +The Board of Directors and Stockholders of +Patterson Energy, Inc. +In our opinion, the consolidated financial statements listed in the +accompanying index present fairly, in all material respects, the financial +position of Patterson Energy, Inc. and Subsidiaries at December 31, 1999 and +2000 and the results of their operations and their cash flows for each of the +three years in the period ended December 31, 2000, in conformity with accounting +principles generally accepted in the United States of America. In addition, in +our opinion, the financial schedule listed in Item 14(a) present fairly, in all +material respects, the information set forth therein, when read in conjunction +with the related consolidated financial statements. These financial statements +and financial statement schedule are the responsibility of the Company's +management; our responsibility is to express an opinion on these financial +statements and financial statement schedule based on our audits. We conducted +our audits of these statements in accordance with auditing standards generally +accepted in the United States of America, which require that we plan and perform +the audit to obtain reasonable assurance about whether the financial statements +are free of material misstatement. An audit includes examining, on a test basis, +evidence supporting the amounts and disclosures in the financial statements, +assessing the accounting principles used and significant estimates made by +management, and evaluating the overall financial statement presentation. We +believe that our audits provide a reasonable basis for our opinion. +PricewaterhouseCoopers LLP +Fort Worth, Texas +February 27, 2001 +F-2 +40 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +DECEMBER 31, +------------------------------- +1999 2000 +---- ---- +(IN THOUSANDS, EXCEPT FOR SHARE +DATA) +ASSETS +Current assets: +Cash and cash equivalents................................. $ 8,792 $ 59,355 +Accounts receivable: +Trade, less allowance for doubtful accounts of $364,519 +and $1,502,532 at December 31, 1999 and 2000, +respectively.......................................... 41,571 78,364 +Oil and natural gas sales.............................. 803 1,255 +Federal income taxes receivable........................... -- 2,447 +Inventories............................................... 1,970 12,186 +Deferred income taxes..................................... 964 9,133 +Undeveloped oil and natural gas properties held for +resale................................................. 2,658 1,680 +Other..................................................... 2,006 3,343 +---------- ---------- +Total current assets.............................. 58,764 167,763 +Property and equipment, at cost, net........................ 133,824 202,592 +Intangible assets, net...................................... 41,818 38,641 +Other....................................................... 1,851 1,590 +---------- ---------- +Total assets...................................... $ 236,257 $ 410,586 +========== ========== +LIABILITIES AND STOCKHOLDERS' EQUITY +Current liabilities: +Current maturities of notes payable....................... $ -- $ 4,477 +Accounts payable: +Trade.................................................. 23,676 28,484 +Revenue distribution................................... 2,407 3,896 +Other.................................................. 1,201 10,119 +Accrued expenses.......................................... 4,432 9,902 +---------- ---------- +Total current liabilities......................... 31,716 56,878 +Deferred income taxes, net.................................. 1,688 30,083 +Other....................................................... 65 880 +Notes payable, net of current maturities.................... 50,000 19,939 +---------- ---------- +Total liabilities................................. 83,469 107,780 +---------- ---------- +Commitments and contingencies............................... -- -- +Stockholders' equity: +Preferred stock, par value $.01; authorized 1,000,000 +shares, no shares issued............................... -- -- +Common stock, par value $.01; authorized 50,000,000 shares +with 32,675,678 and 37,477,276 issued and 32,675,678 +and 37,177,276 outstanding at December 31, 1999 and +2000, respectively..................................... 327 375 +Additional paid-in capital................................ 117,597 245,462 +Retained earnings......................................... 34,864 58,619 +Treasury stock, at cost, 300,000 shares at December 31, +2000................................................... -- (1,650) +---------- ---------- +Total stockholders' equity........................ 152,788 302,806 +---------- ---------- +Total liabilities and stockholders' equity........ $ 236,257 $ 410,586 +========== ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-3 +41 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +YEAR ENDED DECEMBER 31, +--------------------------------------- +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS, EXCEPT PER SHARE DATA) +Operating revenues: +Drilling............................................. $ 165,997 $ 131,287 $ 260,233 +Drilling fluids sales................................ 13,397 11,686 32,053 +Oil and natural gas sales............................ 5,641 6,834 13,619 +Well operation fees.................................. 1,442 1,567 1,978 +Other................................................ 87 162 18 +---------- ---------- ---------- +186,564 151,536 307,901 +---------- ---------- ---------- +Operating costs and expenses: +Direct drilling costs................................ 128,838 113,569 190,234 +Drilling and completion fluids....................... 10,205 9,864 26,545 +Lease operating and production....................... 1,924 1,720 3,245 +Impairment of proved oil and natural gas +properties........................................ 3,816 275 -- +Exploration costs.................................... 669 611 663 +Dry holes and abandonments........................... 1,083 169 964 +Depreciation, depletion and amortization............. 28,091 28,156 33,133 +General and administrative........................... 9,313 7,299 11,394 +---------- ---------- ---------- +183,939 161,663 266,178 +---------- ---------- ---------- +Operating income (loss)................................ 2,625 (10,127) 41,723 +---------- ---------- ---------- +Other income (expense): +Net gain on sale of assets........................... 636 129 194 +Interest income...................................... 767 445 999 +Interest expense..................................... (4,471) (4,101) (4,997) +Other................................................ 211 186 80 +---------- ---------- ---------- +(2,857) (3,341) (3,724) +---------- ---------- ---------- +Income (loss) before income taxes...................... (232) (13,468) 37,999 +---------- ---------- ---------- +Income tax expense (benefit): +Current.............................................. (6,358) 2,767 (1,697) +Deferred............................................. 6,451 (7,108) 15,941 +---------- ---------- ---------- +93 (4,341) 14,244 +---------- ---------- ---------- +Net income (loss)...................................... $ (325) $ (9,127) $ 23,755 +========== ========== ========== +Net income (loss) per common share: +Basic................................................ $ (0.01) $ (0.28) $ 0.69 +========== ========== ========== +Diluted.............................................. $ (0.01) $ (0.28) $ 0.66 +========== ========== ========== +Weighted average number of common shares outstanding: +Basic................................................ 31,645 32,499 34,347 +========== ========== ========== +Diluted.............................................. 31,645 32,499 35,753 +========== ========== ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-4 +42 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +COMMON STOCK +------------------ ADDITIONAL +NUMBER PAID-IN RETAINED TREASURY +OF SHARES AMOUNT CAPITAL EARNINGS STOCK TOTAL +--------- ------ ---------- -------- -------- ----- +(IN THOUSANDS) +December 31, 1997......... 30,967 $ 310 $ 102,306 $ 44,316 $ -- $ 146,932 +Issuance of common +stock................ 571 5 9,941 -- -- 9,946 +Exercise of stock +options.............. 133 2 297 -- -- 299 +Net loss................ -- -- -- (325) -- (325) +------- ------ ---------- --------- --------- ---------- +December 31, 1998......... 31,671 317 112,544 43,991 -- 156,852 +Issuance of common +stock................ 826 8 4,200 -- -- 4,208 +Stock option +compensation......... -- -- 250 -- -- 250 +Exercise of stock +options.............. 179 2 603 -- -- 605 +Net loss................ -- -- -- (9,127) -- (9,127) +------- ------ ---------- --------- --------- ---------- +December 31, 1999......... 32,676 327 117,597 34,864 -- 152,788 +Issuance of common +stock................ 4,203 42 120,964 -- -- 121,006 +Issuance of stock +purchase warrant..... -- -- 900 -- -- 900 +Treasury stock +acquired............. -- -- -- -- (1,650) (1,650) +Exercise of stock +options.............. 598 6 3,225 -- -- 3,231 +Tax benefit related to +exercise of stock +options.............. -- -- 2,776 -- -- 2,776 +Net income.............. -- -- -- 23,755 -- 23,755 +------- ------ ---------- --------- --------- ---------- +December 31, 2000......... 37,477 $ 375 $ 245,462 $ 58,619 $ (1,650) $ 302,806 +======= ====== ========== ========= ========= ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-5 +43 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +YEARS ENDED DECEMBER 31, +------------------------------ +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Cash flows from operating activities: +Net income (loss)......................................... $ (325) $ (9,127) $ 23,755 +Adjustments to reconcile net income (loss) to net cash +provided by operating activities: +Abandonment of oil and natural gas properties............. 694 169 964 +Depreciation, depletion and amortization.................. 28,091 28,156 33,133 +Impairment of proved oil and natural gas properties....... 3,816 275 -- +Net gain on sale of assets................................ (636) (129) (194) +Deferred income tax expense (benefit)..................... 6,451 (7,108) 15,941 +Compensation related to issuance of stock options......... -- 250 -- +Change in operating assets and liabilities: +(Increase) decrease in trade accounts receivable..... 16,116 (12,955) (25,969) +(Increase) decrease in oil and natural gas sales +receivable........................................ 347 (377) (452) +Increase in inventories.............................. (1,283) (687) (1,520) +(Increase) decrease in federal income taxes +receivable........................................ (8,400) 8,400 (2,447) +Decrease in undeveloped oil and natural gas +properties held for resale........................ 873 556 14 +Increase in other current assets..................... (475) (699) (1,199) +Increase (decrease) in trade accounts payable........ (2,378) 13,928 (3,918) +Increase (decrease) in revenue distribution +payable........................................... (1,962) 1,017 1,489 +Decrease in state and federal income taxes payable... (6,874) -- -- +Increase (decrease) in accrued expenses.............. (1,972) 1,262 3,657 +Increase (decrease) in other current payables........ (1,496) 1,128 5,826 +Decrease in other liabilities........................ (595) (27) (75) +-------- -------- -------- +Net cash provided by operating activities......... 29,992 24,032 49,005 +-------- -------- -------- +Cash flows from investing activities: +Net sales of investment securities........................ 566 -- -- +Acquisitions.............................................. (45,453) -- (17,807) +Purchases of property and equipment....................... (34,148) (19,085) (57,153) +Proceeds from sales of property and equipment............. 1,361 1,248 1,125 +Change in other assets.................................... 567 (1,281) 630 +-------- -------- -------- +Net cash used in investing activities............. (77,107) (19,118) (73,205) +-------- -------- -------- +Cash flows from financing activities: +Proceeds from notes payable............................... 40,150 50,000 14,416 +Payments on notes payable................................. (7,686) (55,714) (40,000) +Issuance of common stock.................................. -- -- 98,766 +Purchase of treasury stock................................ -- -- (1,650) +Proceeds from exercise of stock options................... 299 606 3,231 +-------- -------- -------- +Net cash provided by (used in) financing +activities...................................... 32,763 (5,108) 74,763 +-------- -------- -------- +Net increase (decrease) in cash and cash +equivalents..................................... (14,352) (194) 50,563 +Cash and cash equivalents at beginning of year.............. 23,338 8,986 8,792 +-------- -------- -------- +Cash and cash equivalents at end of year.................... $ 8,986 $ 8,792 $ 59,355 +======== ======== ======== +The accompanying notes are an integral part of these consolidated financial +statements. +F-6 +44 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED) +YEAR ENDED DECEMBER 31, +------------------------------ +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Supplemental disclosure of cash flow information: +Cash paid during the period for: +Interest........................................ $ 4,471 $ 3,782 $ 5,117 +Income taxes.................................... 8,000 48 3,200 +Noncash investing and financing activities: +During 2000, the Company acquired WEK Drilling Co., Inc., High Valley +Drilling, Inc., and the drilling and completion fluids operations of Ambar, +Inc., for an aggregate purchase price of approximately $40.9 million of which +approximately $17.8 million was paid in cash as follows: +(IN THOUSANDS) +Purchase price.............................................. $ 40,947 +Less non-cash items: +Common stock issued....................................... (22,240) +Warrants issued........................................... (900) +---------- +Total cash paid................................... $ 17,807 +========== +During 1999, the Company issued 825,776 shares of its common stock in two +separate unrelated transactions to acquire the drilling assets of Padre +Industries, Inc. for an aggregate purchase price of approximately $4.0 million +(see Notes 2 and 9) and other drilling equipment for approximately $208,000 (see +Note 9). +During 1998, the Company acquired Lone Star Mud, Inc., Robertson Onshore +Drilling Company and Tejas Drilling Fluids, Inc. for an aggregate purchase price +of approximately $58.8 million of which, approximately $45.5 million was paid in +cash as follows (see Note 2): +(IN THOUSANDS) +Purchase price.............................................. $ 58,799 +Less non-cash items: +Common stock issued....................................... (9,946) +Debt assumed.............................................. (3,400) +--------- +Total cash paid................................... $ 45,453 +========= +The accompanying notes are an integral part of these consolidated financial +statements. +F-7 +45 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +A summary of the significant accounting policies follows: +Principles of consolidation -- The consolidated financial statements +include the accounts of Patterson Energy, Inc. ("Patterson") and its +wholly-owned subsidiaries, (collectively referred to herein as "Patterson" or +the "Company"). All significant intercompany accounts and transactions have been +eliminated. +Description of business -- The Company engages in onshore contract drilling +of oil and natural gas, the development, exploration, acquisition and production +of oil and natural gas and provides contract drilling fluid services to the oil +and natural gas industry. The Company provides contract drilling services to +major oil and natural gas companies and independent producers in Texas, New +Mexico, Oklahoma, Louisiana and Utah. +The contract drilling business experienced increased demand for drilling +services from 1995 through the third quarter of 1997 due to stronger crude oil +and natural gas prices. The increase in demand returned beginning in mid-1999 +and has continued through 2000. However, except for that period and other +occasional upturns, the market for onshore contract drilling and other related +services has generally been depressed since mid-1982, when crude oil and natural +gas prices began to weaken. A particularly sharp decline in demand for these +services occurred in 1986 because of the worldwide collapse in crude oil prices. +Since this time and except during the occasional upturns, there have been +substantially more drilling rigs available than necessary to meet demand in most +operating and geographic segments of the domestic drilling industry. In addition +to adverse effects that future declines in demand could have on the Company, +ongoing movement or reactivation of onshore drilling rigs or new construction of +drilling rigs could adversely affect rig utilization rates and pricing, even in +an environment of stronger oil and natural gas prices and increased drilling +activity. The Company cannot predict either the future level of demand for its +contract drilling and other related services or future conditions in the oil and +natural gas industry. The Company's rig utilization rate reached an all time +high of approximately 91.5% in the third quarter of 1997, but has weakened since +then due to the significant reduction in the price of crude oil during 1998 and +the first half of 1999. Although there has been significant improvement in oil +and natural gas prices since mid-1999, the Company expects such commodity prices +to continue to be volatile and, therefore, to affect the financial condition and +operations of the Company and its ability to access capital. +Management estimates -- The preparation of financial statements in +conformity with generally accepted accounting principles requires management to +make estimates and assumptions that affect the reported amounts of assets and +liabilities and disclosure of contingent assets and liabilities at the date of +the financial statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those estimates. +Drilling operations -- The Company follows the percentage-of-completion +method of accounting for footage and day work drilling arrangements. Under this +method all drilling revenues, direct costs and appropriate portions of indirect +costs, related to the contracts in progress, are recognized as contract drilling +services are performed. +Due to the nature of turnkey drilling arrangements, the Company follows the +completed contract method of accounting for such arrangements. Under this +method, all drilling advances, direct costs and appropriate portions of indirect +costs (including maintenance, repairs and depreciation) related to the contracts +in progress are deferred and recognized as revenues and expenses in the period +the contracts are completed. +Provisions for losses are made on incomplete contracts when estimated total +costs are expected to exceed total estimated revenues. +Inventories -- Inventories consist primarily of chemical products to be +used in conjunction with the Company's contract drilling fluid activities. The +inventories are stated at the lower of cost or market, determined by the +first-in, first-out method. +F-8 +46 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED) +Undeveloped oil and natural gas properties held for resale -- Undeveloped +oil and natural gas properties held for resale represent leasehold interests in +unproven oil and natural gas properties which the Company expects to sell or +develop under arrangements which will provide for reimbursement of such costs to +the Company. Such properties are carried at the lower of cost or net realizable +value. The Company recognizes gains or losses upon disposition or impairment of +the properties. +Property and equipment -- Property and equipment (other than oil and +natural gas) -- Property and equipment is carried at cost less accumulated +depreciation. Depreciation is provided on the straight-line method over the +estimated useful lives as defined below. The Company incurred depreciation +expense of approximately $20.2 million, $22.0 million and $25.9 million for the +years ended December 31, 1998, 1999 and 2000, respectively. +LIVES (YEARS) +------------- +Drilling rigs and related equipment......................... 2-15 +Office furniture............................................ 3-10 +Buildings................................................... 5-20 +Automotive equipment........................................ 2-7 +Other....................................................... 3-7 +Oil and natural gas properties -- The Company follows the successful +efforts method of accounting, using the field as its accumulation center for +capitalized costs. Under the successful efforts method of accounting, costs +which result directly in the discovery of oil and natural gas reserves and all +development costs are capitalized. Exploration costs which do not result +directly in discovering oil and natural gas reserves are charged to expense as +incurred. The capitalized costs, consisting of lease and well equipment, lease +acquisition costs and intangible development costs are depreciated, depleted and +amortized on the units-of-production method, based on petroleum engineer +estimates of recoverable proved developed oil and natural gas reserves of each +respective field. The Company incurred depletion expense of approximately $4.6 +million, $2.7 million and $3.4 million for the years ended December 31, 1998, +1999 and 2000, respectively. +Impairment of long-lived assets -- Net capitalized costs of long-lived +assets, certain identifiable intangibles and goodwill are reduced to reflect an +amount which is expected to be recovered through the future cash flows generated +by the use of the related assets. Impairment of proved oil and natural gas +properties is periodically assessed based on estimated future net cash flows at +a field level as determined by an independent reserve engineer. The Company +incurred approximately $3.8 million and $275,000 of impairment to such +properties for the years ended December 31, 1998 and, 1999 respectively. +Impairment to the Company's oil and natural gas properties was primarily +attributable to a significant decline in the market price of crude oil and/or +revisions to existing reserve estimates. +Maintenance and repairs -- Maintenance and repairs are charged against +operations. Renewals and betterments which extend the life or improve existing +properties are capitalized. +Retirements -- Upon disposition or retirement of property and equipment +(other than oil and natural gas properties), the cost and related accumulated +depreciation are removed and the gain or loss thereon, if any, is credited or +charged to operations. The Company recognizes the gain or loss on the sale of +either a part of a proved oil and natural gas property or an entire proved oil +and natural gas property constituting a part of a field upon the sale or +disposition of such. The unamortized cost of the property or group of +properties, a part of which was sold or otherwise disposed of, is apportioned to +the interest sold and the interest retained on the basis of the fair value of +those interests. +Intangible assets -- Intangible assets consist primarily of goodwill and +covenants not to compete arising from business combinations (see Notes 2 and 5). +The values assigned to intangible assets, based in part upon +F-9 +47 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED) +independent appraisals, are amortized on a straight line basis. Goodwill, +representing the excess of the purchase price over the estimated fair value of +the net assets of the acquired business, is amortized over the period of +expected benefit of 15 years. Covenants not to compete are amortized over their +contractual lives. Amortization expense charged to operations for the years +ended December 31, 1998, 1999 and 2000 was approximately $3.3 million, $3.6 +million and $3.8 million, respectively. +Earnings per share -- The Company provides a dual presentation of its +earnings per share; Basic Earnings per Share ("Basic EPS") and Diluted Earnings +per Share ("Diluted EPS") in its Consolidated Statements of Operations. 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. Dilutive securities, consisting of certain stock options and +warrants as described in Note 10, of approximately 1.5 million and 2.4 million +were excluded from the December 31, 1998 and 1999 calculations of Diluted EPS as +a result of the Company's net loss for each of those years. For the year ended +December 31, 2000, dilutive securities included in the calculation of Diluted +EPS were 1.4 million. +Stock splits -- On July 25, 1997 and January 23, 1998, the Company effected +two-for-one splits of its common stock. All information regarding earnings per +share, weighted average number of common shares outstanding, stock options and +warrants issued and exercised and all other related disclosures herein reflect +the effects of the stock splits for all periods presented (see Note 9). +Income taxes -- The asset and liability method is used in accounting for +income taxes. Under this method, deferred tax assets and liabilities are +recognized for operating loss and tax credit carryforwards and for the future +tax consequences attributable to differences between the financial statement +carrying amounts of existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the years in which those temporary +differences are expected to be recovered or settled. The effect on deferred tax +assets and liabilities of a change in tax rates is recognized in the results of +operations in the period that includes the enactment date. 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 -- The Company grants stock options to employees +and non-employee directors under stock-based incentive compensation plans, (the +"Plans"). The Company uses the intrinsic value based method of accounting for +the Plans. Under this method, the Company records no compensation expense for +stock options granted when the exercise price for options granted is equal to +the fair market value of the Company's stock on the date of the grant. +Statement of cash flows -- For purposes of reporting cash flows, cash and +cash equivalents include cash on hand, cash on deposit and unrestricted +certificates of deposit with original maturities of 90 days or less. +Recently Issued Accounting Standards -- The Company adopted Statement of +Financial Accounting Standards No. 133, as amended, "Accounting for Derivative +Instruments and Hedging Activities" ("SFAS No. 133") on January 1, 2001. SFAS +No. 133 establishes accounting and reporting standards for derivatives or +instruments and for hedging activities. It requires enterprises to recognize all +derivatives as either assets or liabilities in the balance sheet and measure +those instruments at fair value. The requisite accounting for changes in the +fair value of a derivative depends on the intended use of the derivative and the +resulting designation. The Company was not required to record any transitional +adjustment upon the adoption of SFAS No. 133. +Reclassifications -- Certain reclassifications have been made to the 1998 +and 1999 consolidated financial statements in order for them to conform with the +2000 presentation. The reclassifications had no effect on net income (loss) or +stockholders' equity for these years. +F-10 +48 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2. MERGERS AND ACQUISITIONS +2000 MERGER AND ACQUISITIONS +WEK Drilling Co., Inc. -- On March 31, 2000, the Company acquired the +outstanding stock of WEK Drilling Co., Inc., a privately held, non-affiliated +drilling company with its principal operations in Southeast New Mexico. The +purchase price of $6.8 million, which is net of cash acquired, was funded using +$5.66 million of proceeds from the Company's existing credit facility and 53,000 +shares of the Company's common stock valued at $29.0625 per share and +approximately $77,000 of direct costs incurred related to the transaction. The +assets acquired consisted of four operable drilling rigs, other related +equipment, and working capital of $1.2 million. Immediately following the +transaction, certain assets unrelated to the oil and natural gas industry were +sold back to one of the previous owners for a cash payment of $1.0 million. The +purchase price of $6.8 million, less the $1.0 million of unrelated assets that +were subsequently sold and the net working capital acquired, was allocated among +the acquired assets based upon the estimated fair market value of the drilling +rigs and related equipment. +High Valley Drilling, Inc. -- On June 2, 2000, the Company completed the +merger of High Valley Drilling, Inc., a privately held, non-affiliated company, +with and into Patterson Drilling LP, a wholly owned subsidiary of Patterson +Energy, Inc. The purchase price of $21.8 million was funded using 1.150 million +shares of common stock valued at $18 per share, three-year warrants to acquire +127,000 shares at $22 per share and approximately $208,000 of direct costs +incurred related to the transaction. Using a Black-Scholes model, the warrants +were valued at $900,000. The assets acquired consisted of eight drilling rigs +and other related equipment. The purchase price was allocated among such assets +based upon the estimated fair market value of the drilling rigs and related +equipment. +Ambar, Inc. -- On October 3, 2000, the Company completed, through a wholly +owned subsidiary, the acquisition of the drilling and completion fluid +operations of Ambar, Inc., a non-affiliated entity with its principal operations +in Louisiana, the Gulf Coast region of South Texas and the Gulf of Mexico. The +purchase price of $12.4 million consisted of cash of $11.7 million and $680,000 +of direct costs incurred related to the acquisition. The assets acquired +included net working capital of approximately $7.8 million (current assets of +$18.2 million and current liabilities assumed of $10.4 million), fixed assets +with a market value of $15.7 million and other trademarks and intellectual +property which are specific to the division's operations. The purchase price, +net of working capital acquired, was allocated to the fixed assets. +The Company's operating results include the operations of the acquired +entities since their respective acquisition dates. The following summary, +prepared on a pro forma basis, combines the consolidated results of operations +as if the transactions had occurred on January 1, 1999, after including the +impact of certain adjustments, such as restatement of depreciation using fair +values instead of book values of the assets acquired, the increased interest +expense on the acquisition debt and the related income tax effects. +YEAR ENDED DECEMBER 31, +-------------------------- +1999 2000 +----------- ----------- +(UNAUDITED) +(IN THOUSANDS, EXCEPT PER +SHARE AMOUNTS) +Revenues................................................... $ 217,844 $ 357,995 +Net income (loss).......................................... (10,157) 24,844 +Net income per basic share................................. $ (0.30) $ 0.70 +Net income per diluted share............................... (0.30) 0.70 +The pro forma results have been prepared for comparative purposes only and +do not purport to be indicative of what would have occurred had the acquisition +been made as of the date indicated. In addition, +F-11 +49 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2. MERGERS AND ACQUISITIONS -- (CONTINUED) +they are not intended to be a projection of future results and do not reflect +any synergies that might be achieved from combined operations. +1999 ACQUISITION +Padre Industries, Inc. -- On January 27, 1999, the Company completed the +acquisition of five drilling rigs and other related equipment from a privately +held, non-affiliated entity based in Corpus Christi, Texas. The purchase price +consisted of 800,000 shares of the Company's stock at a guaranteed value of +$5.00 per share. As part of the acquisition agreement, the Company had the +option exercisable on February 1, 2000 to buy back 300,000 of the 800,000 shares +at $5.50 per share. The Company exercised its option on February 1, 2000. The +purchase price of $4.0 million was allocated among such assets based upon the +estimated fair market value of the drilling rigs and related equipment. +1998 MERGER AND ACQUISITIONS +Lone Star Mud, Inc. -- On January 5, 1998, the Company acquired 100% of the +outstanding stock of Lone Star Mud, Inc. ("Lone Star"), a privately-owned, +non-affiliated company based in Midland, Texas. The purchase price of +approximately $13.0 million consisted of $1.4 million in cash, 571,328 shares of +the Company's common stock valued at $17.41 per share, the assumption of $1.6 +million of debt and approximately $3,300 of other direct costs incurred relative +to the transaction. Pursuant to certain terms of the Company's existing loan +agreement with Norwest Bank Texas, N.A. ("Norwest"), the outstanding balance of +the above mentioned debt was paid in full. The purchase price was allocated +based upon the fair value of the net assets acquired and resulted in the +recognition of approximately $9.9 million of goodwill. +Robertson Onshore Drilling Company -- On February 6, 1998, the Company +completed the merger of Robertson Onshore Drilling Company ("Robertson") a +privately-owned, non-affiliated, contract drilling company based in Dallas, +Texas, with and into Patterson Onshore Drilling Company, a wholly-owned +subsidiary of Patterson Drilling Company. The purchase price of approximately +$42.2 million was funded using cash on hand of approximately $3.25 million, +proceeds of $36.75 million provided by the Company's line of credit, the +assumption of $1.8 million of debt and approximately $444,000 of direct costs +incurred related to the acquisition. The assets acquired consisted of 15 +operable drilling rigs and a shop and yard located in Liberty City, Texas. The +purchase price was allocated based upon the estimated fair value of the net +assets acquired and resulted in the recognition of approximately $10.7 million +of goodwill. +Tejas Drilling Fluids, Inc. -- On September 17, 1998, the Company acquired +100% of the outstanding stock of Tejas Drilling Fluids, Inc. ("Tejas"), a +privately-owned, non-affiliated company based in Corpus Christi, Texas for $3.5 +million cash and approximately $74,000 of other direct costs incurred relative +to the transaction. The fair market values of the assets acquired were estimated +and the purchase price was allocated accordingly, resulting in the recognition +of approximately $2.1 million of goodwill and $1.3 million of covenants not to +compete. +The aforementioned acquisitions completed during fiscal years 1998, 1999 +and 2000 have been accounted for as purchases and the related results of +operations and cash flows of the acquired entities have been included in the +consolidated financial statements since their respective dates of acquisition. +3. CASH +Included in cash as of December 31, 1999 and 2000 was approximately $2.4 +million and $3.9 million respectively, of monthly oil and natural gas sales to +be distributed to revenue owners subsequent to year-end. +F-12 +50 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +4. PROPERTY AND EQUIPMENT +Property and equipment consisted of the following at December 31, 1999 and +2000 (in thousands): +1999 2000 +---- ---- +Drilling rigs and related equipment......................... $ 215,312 $ 297,461 +Producing oil and natural gas properties.................... 32,962 37,646 +Other equipment............................................. 2,143 9,379 +Buildings................................................... 4,226 6,297 +Land........................................................ 1,492 2,123 +---------- ---------- +256,135 352,906 +Less accumulated depreciation and depletion................. (122,311) (150,314) +---------- ---------- +$ 133,824 $ 202,592 +========== ========== +5. INTANGIBLE ASSETS +Intangible assets consisted of the following at December 31, 1999 and 2000 +(in thousands): +1999 2000 +---- ---- +Goodwill.................................................... $ 46,983 $ 46,983 +Covenants not to compete.................................... 1,673 1,673 +Other....................................................... 979 1,341 +---------- ---------- +49,635 49,997 +Less accumulated amortization............................... (7,817) (11,356) +---------- ---------- +$ 41,818 $ 38,641 +========== ========== +6. ACCRUED EXPENSES +Accrued expenses consisted of the following at December 31, 1999 and 2000 +(in thousands): +1999 2000 +---- ---- +Salaries, wages, related payroll taxes and benefits......... $ 2,318 $ 4,171 +Workers' compensation liability............................. 1,370 1,686 +Sales tax................................................... 359 944 +Accrued purchases........................................... -- 1,939 +Other....................................................... 385 1,162 +---------- ---------- +$ 4,432 $ 9,902 +========== ========== +F-13 +51 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +7. NOTES PAYABLE +Notes payable consisted of the following at December 31, 1999 and 2000 (in +thousands): +1999 2000 +---- ---- +Line of credit agreement with Transamerica Equipment +Financial Services Corporation providing for an advancing, +non-revolving credit facility of $70 million ($60 million +at December 31, 1999), monthly payments of interest only +at LIBOR plus 3.10% to 3.51% (9.835% to 10.245% at +December 31, 2000) through January 1, 2001 at which time +the outstanding principal balance converts to a term loan +with a maturity of January 1, 2006. The obligation is +collateralized by drilling rigs and other related +equipment................................................. $ 50,000 $ 24,416 +Less current maturities................................... -- (4,477) +--------- --------- +$ 50,000 $ 19,939 +========= ========= +On December 22, 1999, the Company entered into a credit agreement with +Transamerica Equipment Financial Services Corporation (the "Transamerica +Credit") providing for a non-revolving credit facility of $60.0 million. The +terms of the credit agreement included payments of interest only through January +1, 2001 at which time the outstanding principal amount would convert to a term +loan with a maturity date of January 1, 2006. The Company borrowed $50 million +under the Transamerica Credit and paid, prior to maturity, principal and +interest amounts then outstanding under an existing credit facility. As a +result, the Company expensed approximately $123,000 of deferred financing costs +associated with the other facility. This amount was included in interest expense +at December 31, 1999, as management does not consider the amount significant +enough to warrant treatment as an extraordinary item. The Company borrowed an +additional $9.4 million against the credit facility in March 2000. In July 2000, +the credit facility was amended to increase the maximum availability from $60 +million to $70 million and an additional $5 million was borrowed at that time by +the Company. In September 2000, the note was modified to allow the Company to +prepay $40 million of the outstanding balance. The Company paid $200,000 in +prepayment penalties which is included in interest expense, as management does +not consider the amount significant enough to warrant treatment as an +extraordinary item. +The Transamerica Credit contains a number of representations, warranties +and covenants, the breach of which, at the election of Transamerica, would +accelerate the maturity date of the outstanding principal balance. +The more restrictive covenants include: +- Maintenance on a quarterly basis of a ratio of consolidated cash flow to +the sum of all principal and interest payments and unfinanced capital +expenditure costs during the measurement period of at least 1.2 to 1.0; +- Maintenance on an annual basis of a ratio of total liabilities to +tangible net worth not to exceed 3.0 to 1.0; +- Maintenance on an annual basis of a minimum tangible net worth of $80.0 +million; +- Without written consent of Transamerica, the Company cannot conduct any +business not currently being conducted by the Company, nor liquidate, +dissolve or merge into any other entity; and +- The Company shall not pay, or authorize the payment of, any dividends on +any stock, debenture or other security without the prior written consent +of Transamerica. +F-14 +52 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +7. NOTES PAYABLE -- (CONTINUED) +Five-year maturities of note payable -- Scheduled maturities of debt for +the periods subsequent to December 31, 2000, are as follows (in thousands): +2001........................................................ $ 4,477 +2002........................................................ 4,883 +2003........................................................ 4,883 +2004........................................................ 4,883 +2005........................................................ 4,883 +Thereafter.................................................. 407 +--------- +Total............................................. $ 24,416 +========= +The estimated fair value of the Company's long-term debt obligations +approximates its related carrying value as the underlying debt agreement bears +interest based upon current market rates. +The Company maintains letters of credit in the aggregate amount of $230,289 +with a bank for the benefit of an insurance company as collateral for +retrospective premiums and retained losses which could become payable under the +terms of the Company's insurance contract. These letters of credit expire in +November of each calendar year, but provide for an indefinite number of annual +extensions of the expiration date and are fully collateralized by the Company's +cash. No amounts have been drawn under the letters of credit. +8. COMMITMENTS AND CONTINGENCIES +Contingencies -- The Company's contract services and oil and natural gas +exploration and production operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in personal injury +or death, suspended drilling operations, damage to, or destruction of equipment, +damage to producing formations and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains general +liability insurance coverage of $2.0 million per occurrence with $2.0 million of +aggregate coverage and excess liability and umbrella coverages up to $40.0 +million per occurrence with a $40.0 million aggregate. +The Company believes it is adequately insured for public liability and +property damage to others with respect to its operations. However, such +insurance may not be sufficient to protect the Company against liability for all +consequences of well disasters, extensive fire damage or damage to the +environment. The Company also carries insurance to cover physical damage to, or +loss of, its rigs; however, it does not carry insurance against loss of earnings +resulting from such damage or loss. The Company's lender who has a security +interest in the drilling rigs is named as loss payee on the physical damage +insurance on such rigs. +The Company is involved in various routine litigation incident to its +business. In the Company's opinion, none of these proceedings will have a +material adverse effect on the Company's financial condition, results of +operations or liquidity. +9. STOCKHOLDERS' EQUITY +During September 2000, the Company issued 3,000,000 shares of its commons +stock at a public price of $34.50 per share. An underwriting discount of $1.50 +was paid for a net price of $33.00 per share. Net proceeds from the offering +totaled approximately $98.8 million. +During June 2000, the Company issued 1,150,000 shares of its common stock +and three-year warrants to acquire an additional 127,000 shares at an exercise +price of $22.00 per share, as consideration for certain drilling equipment +acquired from an unrelated entity. The common stock was recorded at $18 per +share its fair market value on the date of purchase and the warrants were valued +at $900,000 using the Black-Scholes model. +F-15 +53 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +9. STOCKHOLDERS' EQUITY -- (CONTINUED) +During March 2000, the Company issued 53,000 shares of its common stock as +consideration for certain drilling equipment acquired from an unrelated entity. +The common stock was recorded at $29.0625 per share, its fair market value on +the date of purchase. +During June 1999, the Company issued 25,776 shares of its common stock as +consideration for certain drilling equipment acquired from an unrelated entity. +The common stock was recorded at $8.0625 per share, its fair market value on the +date of purchase. +On January 27, 1999, the Company issued 800,000 shares of its common stock +as consideration for the Company's acquisition of the drilling assets of Padre +Industries, Inc. The common stock was recorded at its guaranteed value of $5.00 +per share, or an aggregate purchase price of $4.0 million. On February 1, 2000, +the Company exercised its option to buy back 300,000 shares of its common stock +previously issued in conjunction with this acquisition for $5.50 per share. +During January 1998, the Company acquired the outstanding stock of Lone +Star. The purchase price consisted of $1.4 million in cash, 571,328 shares of +the Company's common stock valued at $17.41 per share, the assumption of $1.6 +million of debt and approximately $3,300 of other direct costs. +10. STOCK OPTIONS AND WARRANTS +Employee Stock Incentive Plans -- In August 1993, the Company adopted the +Patterson Energy, Inc. 1993 Stock Incentive Plan (the "Stock Incentive Plan"). +The purpose of the Stock Incentive Plan is to provide continuing incentives to +the Company's key employees, which may include, but shall not necessarily be +limited to, members of the Board of Directors (excluding members of the +Compensation Committee) and officers of the Company. The Stock Incentive Plan +provides for an authorization of 2.8 million shares of common stock for issuance +thereunder. Under the Stock Incentive Plan, the Company may grant to key +employees awards of stock options and restricted stock or any combination +thereof. The Company may grant both incentive stock options ("incentive stock +options") intended to qualify under Section 422 of the Internal Revenue Code of +1986, as amended, and options which are not qualified as incentive stock +options. The options become immediately exercisable in the event of a change in +control (as defined in the Stock Incentive Plan) of the Company. +Under the Stock Incentive Plan, the exercise price of incentive stock +options must be at least equal to the fair market value of the stock on date of +grant and the exercise price of non-incentive stock options may not be less than +80% of the fair market value on date of grant. +Stock options covering a total of 2.77 million shares of common stock (net +of any forfeitures and expirations as defined below) have been granted to date +under the Stock Incentive Plan. The outstanding options were variously granted +since 1995. Each of the options has a 10-year term and the exercise prices were +equal to the fair market value of the Company's common stock on the respective +grant dates. The options granted to the employees vest either (i) 20% a year, +beginning on the grant date and 20% for the next four anniversaries of the date +of grant, (ii) 11.2% a year for the first five years, beginning on the grant +date, and 22% on each of the next two anniversaries of the grant date, or (iii) +0.0% for the first year, approximately 4% for each of the next two anniversaries +and 23% on each of the next four anniversaries of the date of grant. A total of +1,032,400 options granted under the Stock Incentive Plan have been exercised, +149,700 have been forfeited and 61,200 have expired as of December 31, 2000. +Non-Employee Directors' Stock Option Plan -- In June 1995, Patterson +adopted the Non-Employee Directors' Stock Option Plan (the "Outside Directors' +Plan"). The purpose of the Outside Directors' Plan is to encourage and provide +incentive for high level performance by non-employee directors of the Company. +An +F-16 +54 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +aggregate of 120,000 shares of Common Stock are reserved for issuance under the +Outside Directors' Plan to directors who are not employees of the Company. +As required by the Outside Directors' Plan, the exercise price of the +options will be equal to the fair market value of the Company's common stock on +the date of grant. Outside directors are automatically granted options to +purchase 20,000 shares and an additional 4,000 shares for each subsequent year +that they serve up to a maximum of 40,000 shares per director. Each option is +exercisable one year after the date of grant and expires five years from the +date of grant. The options become immediately exercisable in the event of a +change of control (as defined in the Outside Directors' Plan) of the Company. +The table below sets forth information regarding options granted under the +Outside Directors' Plan. Each of the options are granted with an exercise price +per share equal to fair market value on the grant date. A total of 4,000 options +granted under the Outside Directors' Plan have been forfeited and 65,200 options +have been exercised as of December 31, 2000. +DATE GRANTED OPTIONS GRANTED EXERCISE PRICE/SHARE +------------ --------------- -------------------- +June 6, 1995......................................... 40,000 $ 2.250 +June 6, 1996......................................... 8,000 4.313 +July 30, 1996........................................ 20,000 4.375 +June 6, 1997......................................... 8,000 10.000 +July 30, 1997........................................ 4,000 15.813 +June 6, 1998......................................... 8,000 11.063 +July 30, 1998........................................ 4,000 7.375 +June 6, 1999......................................... 8,000 8.875 +July 30, 1999........................................ 4,000 9.625 +June 6, 2000......................................... 4,000 22.188 +July 30, 2000........................................ 4,000 24.688 +November 6, 2000..................................... 40,000 28.625 +--------- +Total options granted...................... 152,000 +========= +Included in the above total are 40,000 options that have been granted to +two new directors. These options are contingent upon shareholder approval of a +Plan amendment. +F-17 +55 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +A summary of the status of the Company's stock options issued under the +Stock Incentive Plan and the Outside Directors' Plan as of December 31, 1998, +1999 and 2000 and the changes during each of the years then ended are presented +below (in thousands): +1998 1999 2000 +--------------------------- --------------------------- --------------------------- +NO. OF NO. OF NO. OF +SHARES OF WEIGHTED SHARES OF WEIGHTED SHARES OF WEIGHTED +UNDERLYING AVERAGE UNDERLYING AVERAGE UNDERLYING AVERAGE +OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE +---------- -------------- ---------- -------------- ---------- -------------- +Outstanding at beginning of the +year.......................... 1,130 $ 9.47 1,475 $ 10.12 2,351 $ 7.70 +Granted at the money.......... 515 9.79 1,144 3.75 93 21.68 +------- -------- ------- -------- ------- -------- +Total granted......... 1,645 9.57 2,619 7.34 2,444 8.23 +Exercised..................... 129 2.25 179 3.39 540 5.29 +Forfeited..................... 30 12.47 83 5.30 40 11.38 +Expired....................... 11 13.26 6 12.34 44 13.79 +------- -------- ------- -------- ------- -------- +Outstanding at end of year...... 1,475 $ 10.12 2,351 $ 7.70 1,820 $ 8.90 +======= ======== ======= ======== ======= ======== +Exercisable at end of year...... 563 $ 9.05 892 $ 9.34 732 $ 11.45 +======= ======== ======= ======== ======= ======== +Weighted average fair value of +options granted during the +year.......................... $ 4.99 $ 2.15 $ 15.55 +======== ======== ======== +The following table summarizes information about stock options outstanding +at December 31, 2000: +OPTIONS OUTSTANDING OPTIONS EXERCISABLE +------------------------------------------------- ------------------------------ +WEIGHTED AVERAGE +NUMBER REMAINING WEIGHTED AVERAGE NUMBER WEIGHTED AVERAGE +RANGE OF EXERCISE PRICES OUTSTANDING CONTRACTED LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICES +------------------------ ----------- ---------------- ---------------- ----------- ---------------- +$1.81 to $5.00............ 794,300 7.74 $ 3.18 100,865 $ 3.32 +$5.01 to $20.00........... 951,200 6.98 $ 12.37 625,680 $ 12.67 +$20.01 to $28.63.......... 74,000 6.47 $ 25.78 5,200 $ 22.13 +----------- ------ -------- --------- -------- +1,819,500 7.29 $ 8.90 731,745 $ 11.45 +=========== ====== ======== ========= ======== +Public Relations Services Stock Options -- In June 1999, the Company issued +options covering a total of 50,000 shares of common stock at an exercise price +of $8.0625 per share to a consultant as partial compensation for public +relations services rendered to the Company. The options granted to the +consultant have an exercise price equal to the fair market value of the stock at +date of grant. The options were fully exercisable upon grant date. The Company +accounted for the option grant in accordance with SFAS No. 123, and as such, a +charge for stock compensation expense of $250,000, which represents the fair +value of the options on the date of grant, is included in general and +administrative expenses for the year ended December 31, 1999. All such options +were exercised in 2000. +F-18 +56 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +Pro Forma Stock-Based Compensation Disclosure -- Had the compensation cost +for the Company's stock-based compensation plan been determined consistent with +SFAS No. 123, the Company's net income (loss) and net income (loss) per common +share for 1998, 1999 and 2000 would approximate the pro forma amounts below: +DECEMBER 31, 1998 DECEMBER 31, 1999 DECEMBER 31, 2000 +-------------------- ------------------------ ----------------------- +AS PRO PRO PRO +REPORTED FORMA AS REPORTED FORMA AS REPORTED FORMA +-------- ----- ----------- ----- ----------- ----- +SFAS No. 123 charge net +of income tax......... $ -- $ 1,817 $ -- $ 2,178 $ -- $ 2,026 +APB 25 charge........... -- -- -- -- -- -- +Net income (loss)....... (325) (2,142) (9,127) (11,305) 23,755 21,729 +======== ========= ========= ========== ========= ========= +Net income (loss) per +common share: +Basic................. $ (0.01) $ (0.07) $ (0.28) $ (0.35) $ 0.69 $ 0.63 +======== ========= ========= ========== ========= ========= +Diluted............... $ (0.01) $ (0.07) $ (0.28) $ (0.35) $ 0.66 $ 0.61 +======== ========= ========= ========== ========= ========= +The fair value of each stock option granted is estimated on the date of +grant using the Black-Scholes option-pricing model with the following +weighted-average assumptions for grants in 1995, 1996, 1997, 1998, 1999, and +2000 respectively; dividend yield of 0.00%; risk-free interest rates are +different for each grant and range from 4.88% to 7.02%; the expected term is 5 +years; and a volatility of 38.68% for all 1995 and 1996 grants, 35.97% for all +1997 grants, 51.08% for all 1998 grants, 61.97% for all 1999 grants and 67.71% +for all 2000 grants. +The effects of applying SFAS No. 123 in this pro forma disclosure are not +indicative of future amounts. SFAS No. 123 does not apply to awards prior to +1995. +Stock Purchase Warrants -- In June 2000, the Company issued 127,000 +warrants exercisable at $22 per share as partial consideration for the purchase +of eight drilling rigs and related equipment. The warrants were fully +exercisable upon date of issuance. If not exercised, the warrants will expire on +June 2, 2003. +F-19 +57 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +Tabular Summary -- The following table summarizes information regarding the +Company's stock options and warrants granted under the provisions of the +aforementioned plans: as well as stock options and warrants issued pursuant to +certain transactions described in Notes 2 and 9: +WEIGHTED AVERAGE +SHARES EXERCISE PRICE +------ ---------------- +GRANTED +1998.................................................... 515,000 $ 9.79 +1999.................................................... 1,193,800 3.93 +2000.................................................... 220,200 21.87 +EXERCISED +1998.................................................... 132,720 $ 2.31 +1999.................................................... 178,770 3.39 +2000.................................................... 540,310 5.29 +SURRENDERED +1998.................................................... 43,568 $ 12.10 +1999.................................................... 89,800 5.80 +2000.................................................... 83,900 12.64 +OUTSTANDING AT YEAR END +1998.................................................... 1,483,568 $ 10.08 +1999.................................................... 2,408,798 7.69 +2000.................................................... 1,946,500 9.76 +EXERCISABLE AT YEAR END +1998.................................................... 573,936 $ 8.96 +1999.................................................... 949,958 9.21 +2000.................................................... 858,745 13.01 +11. LEASES +The Company incurred rent expense, consisting primarily of daily rental +charges for the use of drilling equipment, of $4.3 million, $2.5 million and +$1.8 million, for the periods ended December 31, 1998, 1999 and 2000, +respectively. The Company's obligations under non-cancelable operating lease +agreements are not material to the Company's operations. +12. INCOME TAXES +Components of the income tax provision applicable for federal and state +income taxes are as follows (in thousands): +1998 1999 2000 +---- ---- ---- +Federal income tax expense (benefit): +Current......................................... $ (6,358) $ 2,767 $ (1,731) +Deferred........................................ 6,451 (7,108) 15,496 +--------- --------- --------- +93 (4,341) 13,765 +State income tax expense: +Current......................................... -- -- 34 +Deferred........................................ -- -- 445 +--------- --------- --------- +Total income tax expense (benefit)................ $ 93 $ (4,341) $ 14,244 +========= ========= ========= +F-20 +58 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +12. INCOME TAXES -- (CONTINUED) +The difference between the statutory federal income tax rate and the +effective income tax rate is summarized as follows: +1998 1999 2000 +---- ---- ---- +Statutory tax rate......................................... (34.0)% (34.0)% 35.0% +State income taxes......................................... -- -- 1.1 +Non-amortizable goodwill................................... 102.8 2.2 0.9 +Non-deductible expenses.................................... 12.8 0.3 0.3 +Statutory depletion in excess of basis..................... (44.3) (0.8) (0.4) +Other, net................................................. 2.8 0.1 0.6 +----- ----- ---- +Effective tax rate......................................... 40.1% (32.2)% 37.5% +===== ===== ==== +In assessing the realizability of deferred tax assets, management considers +whether it is more likely than not that some portion or all of the deferred tax +assets will not be realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during the periods in +which those temporary differences become deductible. Management considers the +scheduled reversal of deferred tax liabilities, projected future taxable income, +and tax planning strategies in making this assessment. The Company expects the +deferred tax assets at December 31, 2000 to be realized as a result of the +reversal during the carryforward period of existing taxable temporary +differences giving rise to deferred tax liabilities and the generation of +taxable income in the carryforward period; therefore, no valuation allowance is +necessary. +The tax effect of significant temporary differences representing deferred +tax assets and liabilities and changes therein were as follows (in thousands): +JANUARY 1, NET DECEMBER 31, NET DECEMBER 31, DECEMBER 31, +1998 CHANGE 1998 CHANGE 1999 NET CHANGE 2000 +---------- --------- ------------ --------- ------------ ---------- ------------ +Deferred tax assets: +Net operating loss +carryforwards.................. $ 1,216 $ 218 $ 1,434 $ 10,294 $ 11,728 $ (5,878) $ 5,850 +Investment tax credit +carryforwards.................. 375 -- 375 -- 375 94 469 +AMT credit carryforwards........... 282 -- 282 2,933 3,215 (1,597) 1,618 +Depletion carryforwards............ -- -- -- -- -- -- -- +Other.............................. 1,050 78 1,128 23 1,151 45 1,196 +--------- --------- ---------- --------- ---------- ---------- ---------- +2,923 296 3,219 13,250 16,469 (7,336) 9,133 +Valuation allowance................ -- -- -- -- -- -- -- +--------- --------- ---------- --------- ---------- ---------- ---------- +Deferred tax assets.............. 2,923 296 3,219 13,250 16,469 (7,336) 9,133 +Deferred tax liabilities: +Property and equipment basis +difference................... (3,882) (7,335) (11,217) (5,976) (17,193) (12,890) (30,083) +--------- --------- ---------- --------- ---------- ---------- ---------- +Net deferred tax +liability................ $ (959) $ (7,039) $ (7,998) $ 7,274 $ (724) $ (20,226) $ (20,950) +========= ========= ========== ========= ========== ========== ========== +For tax return purposes, the Company had tax NOL carryforwards of +approximately $16.3 million at December 31, 2000. If unused, the aforementioned +tax NOL carryforwards will expire in 2019. The Company also had available, at +December 31, 2000, $1.6 million of alternative minimum tax credits, which may be +carried forward indefinitely. +13. EMPLOYEE BENEFITS +Effective January 1, 1992, the Company established a 401(k) profit sharing +plan for all eligible employees. Company contributions are discretionary. The +Company made no contribution in 1998 or 1999 and incurred $783,000 of expense in +2000 for a matching contribution. +F-21 +59 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +14. BUSINESS SEGMENTS +The Company conducts its business through three distinct operating +activities: contract drilling of oil and natural gas wells, oil and natural gas +exploration, development, acquisition and production and, to a lesser degree, +providing drilling fluid services to operators in the oil and natural gas +industry. +Contract Drilling Services. The Company markets its contract drilling +services to major oil companies and independent oil and natural gas producers. +The Company owns 131 drilling rigs, 124 of which are operable at December 31, +2000. Currently, 88 of the operable drilling rigs are based in Texas (47 in West +Texas, 26 in South Texas, 11 in East Texas and four in North Texas), 20 are +based in Southeast New Mexico, and four each in Oklahoma, Louisiana, Utah and +Mississippi. The drilling rigs have rated maximum depth capabilities ranging +from 8,000 feet to 25,000 feet. +Oil and Natural Gas Operations. The Company has been engaged in the +development, exploration, acquisition and production of oil and natural gas +since 1982. The Company's oil and natural gas activities are designed to +complement its land drilling operations and diversify the Company's overall +business strategy. These activities are primarily focused in mature producing +regions in the Permian Basin and South Texas. Oil and natural gas operations +comprised approximately 5% of the Company's consolidated operating revenues for +the year ended December 31, 2000. The Company's business strategy for its oil +and natural gas operations is to increase its oil and natural gas reserves +primarily through developmental and exploratory drilling in producing areas. At +December 31, 2000, the Company's proved developed reserves were approximately +1.8 million BOE and had a present value (discounted at 10% before income taxes) +of estimated future net revenues of approximately $22.8 million. (See Note 19 +Supplementary Oil and Natural Gas Reserve Information and Related Data). +Drilling and Completion Fluids Services. The Company provides contract +drilling and completion fluids services to numerous operators in the oil and +natural gas industry. Operating revenues derived from these activities +constitute approximately 10% of the Company's consolidated operating revenues +for the year ended December 31, 2000. Patterson believes that these contract +services integrate well with its other core operating activities. The drilling +fluids operations were added by the Company during 1998 with its acquisitions of +Lone Star Mud, Inc. and Tejas Drilling Fluids, Inc. and have operations in +Texas, New Mexico, Oklahoma and Colorado. The scope of the Company's drilling +fluids services was expanded to include completion fluids services by the +purchase of the drilling and completion fluids division of Ambar, Inc. in +October 2000 which has operations in the coastal areas of Texas, Louisiana and +in the Gulf of Mexico. Since the addition of Ambar, its revenues have comprised +of 37% of the total drilling fluids revenues for the year. +F-22 +60 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +14. BUSINESS SEGMENTS -- (CONTINUED) +DECEMBER 31, +------------------------------------ +1998 1999 2000 +---- ---- ---- +Revenues: +Contract drilling.................................... $ 165,997 $ 131,287 $ 260,233 +Oil and natural gas.................................. 7,170 8,563 15,615 +Drilling and completion fluids....................... 13,397 11,686 32,053 +---------- ---------- ---------- +Total revenues......................................... $ 186,564 $ 151,536 $ 307,901 +========== ========== ========== +Income (loss) from operations: +Contract drilling.................................... $ 9,329 $ (10,283) $ 36,933 +Oil and natural gas.................................. (6,217) 1,874 5,614 +Drilling fluids...................................... 360 (1,403) (550) +---------- ---------- ---------- +3,472 (9,812) 41,997 +Interest income...................................... 767 445 999 +Interest expense..................................... (4,471) (4,101) (4,997) +---------- ---------- ---------- +Income (loss) before income taxes.................... $ (232) $ (13,468) $ 37,999 +========== ========== ========== +Identifiable assets: +Contract drilling.................................... $ 185,237 $ 190,617 $ 265,747 +Oil and natural gas.................................. 15,411 18,386 21,232 +Drilling fluids...................................... 20,063 19,117 52,414 +Corporate(a)......................................... 15,894 8,137 71,193 +---------- ---------- ---------- +Total assets........................................... $ 236,605 $ 236,257 $ 410,586 +========== ========== ========== +Depreciation, depletion and amortization: +Contract drilling.................................... $ 22,416 $ 24,417 $ 28,066 +Oil and natural gas.................................. 4,780 2,674 3,601 +Drilling fluids...................................... 895 1,065 1,466 +---------- ---------- ---------- +Total depreciation, depletion and amortization......... $ 28,091 $ 28,156 $ 33,133 +========== ========== ========== +Capital expenditures: +Contract drilling.................................... $ 67,471 $ 17,917 $ 82,593 +Oil and natural gas.................................. 7,734 5,260 5,341 +Drilling fluids...................................... 4,396 195 10,166 +---------- ---------- ---------- +Total capital expenditures............................. $ 79,601 $ 23,372 $ 98,100 +========== ========== ========== +--------------- +(a) Corporate assets primarily include cash on hand managed by the parent +corporation and certain deferred Federal income tax assets. +F-23 +61 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +15. SELECTED QUARTERLY FINANCIAL RESULTS (UNAUDITED) +Quarterly financial information for the three years ended December 31, 2000 +is as follows: +1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL +----------- ----------- ----------- ----------- ----- +2000 +Operating revenues............... $ 58,566 $ 67,139 $ 78,628 $ 103,568 $ 307,901 +Operating income (loss).......... 2,471 7,215 12,136 19,901 41,723 +Net income (loss)................ 911 3,808 6,749 12,287 23,755 +Earnings per share: +Basic............................ $ 0.03 $ 0.12 $ 0.20 $ 0.34 $ 0.69 +Diluted.......................... $ 0.03 $ 0.11 $ 0.19 $ 0.33 $ 0.66 +1999 +Operating revenues............... $ 26,738 $ 30,544 $ 39,812 $ 54,442 $ 151,536 +Operating income (loss).......... (4,871) (3,709) (2,704) 1,157 (10,127) +Net income (loss)................ (3,863) (3,142) (2,354) 232 (9,127) +Earnings per share: +Basic............................ $ (0.12) $ (0.10) $ (0.07) $ 0.01 $ (0.28) +Diluted.......................... $ (0.12) $ (0.10) $ (0.07) $ 0.01 $ (0.28) +1998 +Operating revenues............... $ 60,751 $ 51,150 $ 42,258 $ 32,405 $ 186,564 +Operating income (loss).......... 7,861 3,531 (252) (8,515) 2,625 +Net income (loss)................ 4,533 1,721 (529) (6,050) (325) +Earnings per share: +Basic............................ $ 0.14 $ 0.05 $ (0.02) $ (0.18) $ (0.01) +Diluted.......................... $ 0.14 $ 0.05 $ (0.02) $ (0.18) $ (0.01) +16. CONCENTRATIONS OF CREDIT RISK +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand deposits, temporary +cash investments and trade receivables. +The Company believes that it places its demand deposits and temporary cash +investments with high credit quality financial institutions. At December 31, +1999 and 2000, the Company's demand deposits and temporary cash investments +consisted of the following (in thousands): +1999 2000 +---- ---- +Deposit in FDIC and SIPC-insured institutions under $100,000 +and cash on hand.......................................... $ 1,361 $ 1,653 +Deposit in FDIC and SIPC-insured institutions over $100,000 +and cash on hand.......................................... 11,146 69,376 +--------- ---------- +12,507 71,029 +Less outstanding checks and other reconciling items......... (3,715) (11,674) +--------- ---------- +Cash and cash equivalents................................... $ 8,792 $ 59,355 +========= ========== +Concentrations of credit risk with respect to trade receivables are +primarily focused on companies involved in the exploration and development of +oil and natural gas properties. The concentration is somewhat mitigated by the +diversification of customers for which the Company provides drilling services. +As is general industry practice, the Company does not require customers to +provide collateral. No significant losses from individual contracts were +experienced during the years ended December 31, 1998, 1999 and 2000. Included in +F-24 +62 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +16. CONCENTRATIONS OF CREDIT RISK -- (CONTINUED) +general and administrative expense for the periods ended December 31, 1998, 1999 +and 2000 are provisions for doubtful receivables of $90,000, $0 and $570,000, +respectively. +The carrying values of cash and cash equivalents, marketable securities and +trade receivables approximate fair value due to the short-term maturity of these +assets. +17. RELATED PARTY TRANSACTIONS +Use of Assets -- The Company leases a 1981 Beech King-Air 90 airplane owned +by an affiliate of the Company's Chairman of the Board/Chief Executive Officer. +Under the terms of the lease, the Company pays a monthly rental of $9,200 and +its proportionate share of the costs of fuel, insurance, taxes and maintenance +of the aircraft. The Company paid approximately $211,495, $222,583 and $193,769 +for the lease of the airplane during 1998, 1999 and 2000, respectively. +Contract Drilling Services -- The Company provided contract drilling +services to an affiliated company during 1999 with related revenues of +approximately $275,642. +Sales of Oil -- An affiliate acted as the first purchaser of oil produced +from leases operated by the Company during 1998 and 1999. Sales of oil to that +entity, both royalty and working interest (including the Company) were +approximately $8.1 million and $8.4 million for 1998 and 1999, respectively. +There were no sales of oil to that entity in 2000. +Joint Operation of Oil and Natural Gas Properties -- The Company operates +certain oil and natural gas properties in which the Chairman of the Board/Chief +Executive Officer, the President/Chief Operating Officer and other persons or +entities related to the Company purchased a joint interest ownership with the +Company and other industry partners. The Company made oil and natural gas +production payments (net of royalty) of $10.5 million, $6.1 million and $13.4 +million from these properties in 1998, 1999 and 2000, respectively, to the +aforementioned persons or entities. These persons or entities reimbursed the +Company for joint operating costs of $7.4 million, $5.9 million and $8.0 million +in 1998, 1999 and 2000, respectively. +18. SUBSEQUENT EVENTS +On January 5, 2001, the Company consummated The Agreement and Plan of +Merger among Patterson Energy, Inc., Patterson Drilling Company LP, LLLP +("Patterson Drilling") and Jones Drilling Corporation and certain Asset Purchase +Agreements between Patterson Drilling and Henderson Welding, Inc., L.E.J. Truck +and Crane, Inc., and L.E. Jones Drilling Company. The acquired assets consist of +21 drilling rigs and related equipment. The purchase price of $36.2 million +consisted of 810,070 shares of Patterson's common stock valued at $26.8125 per +share and $10.9 million cash, net of certain working capital adjustments. +On February 5, 2001, the Company announced that its Board of Directors +along with the Board of Directors of UTI Energy Corp., approved a merger of the +two companies. According to the terms of the merger agreement between the +Company and UTI, shareholders of UTI will receive one share of Patterson common +stock for each share of UTI common stock and Patterson will assume UTI's +outstanding options and warrants. The board of directors of the new company will +consist of eleven directors, six of which will be selected by Patterson and five +of which would be selected by UTI. Although the merger agreement does not +specify who will be the officers of the new company, management of the Company +understands that Mark S. Siegel, UTI's Chairman of the Board, would be the +Chairman of the Board and Cloyce A. Talbott, Patterson's Chairman of the Board +and Chief Executive Officer, would be Chief Executive Officer. The combined +company will be the second largest United States land-based drilling service +contractor with 302 drilling rigs and will be called "Patterson-UTI Energy, +Inc." +F-25 +63 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +18. SUBSEQUENT EVENTS -- (CONTINUED) +Under the terms of the merger agreement, both the Company and UTI have +agreed not to solicit competing offers, but the boards of directors of each +company are free to consider and accept an unsolicited offer if, based on advice +of counsel, it believes it must do so in the exercise of its fiduciary duty. In +the event a party accepts an unsolicited offer, or its board of directors +withdraws its recommendation in light of an unsolicited offer, or the +shareholders do not vote to approve the merger because of an unsolicited offer, +the other party would be entitled to receive a breakup fee of $32.5 million plus +reimbursement of expenses of up to $2.5 million. In the event the shareholders +of one party do not vote to approve the merger and the other party is not in +default and is ready, willing and able to perform its agreement, the party whose +shareholders vote against the merger will be required to pay to the other party +$2.5 million, plus up to an additional $2.5 million in expenses. +The merger is subject to customary conditions to closing, including +approval by the shareholders of both companies, as well as any necessary +regulatory filings and approvals, such as the anti-trust provisions of the +Hart-Scott-Rodino Act. There can be no assurance that the merger will be +consummated in accordance with the terms of the merger agreement, if at all. +19. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) +OIL AND GAS EXPENDITURES AND CAPITALIZED COSTS +Gross oil and natural gas expenditures by the Company for the years ended +December 31, 1998, 1999 and 2000 are summarized below (in thousands): +DECEMBER 31, +------------------------------- +1998 1999 2000 +---- ---- ---- +Property acquisition costs.......................... $ 1,585 $ 2,185 $ 798 +Exploration costs................................... 6,510 7,178 5,401 +Development costs................................... 1,126 2,061 1,012 +-------- --------- -------- +$ 9,221 $ 11,424 $ 7,211 +======== ========= ======== +The aggregate amount of capitalized costs of oil and natural gas properties +as of December 31, 1999 and 2000 is comprised of the following (in thousands): +DECEMBER 31, +--------------------- +1999 2000 +---- ---- +Proved properties........................................... $ 32,962 $ 37,646 +Accumulated depreciation, depletion and amortization........ (24,893) (28,338) +--------- --------- +Net proved properties....................................... $ 8,069 $ 9,308 +========= ========= +F-26 +64 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +19. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) -- (CONTINUED) +The following table sets forth information with respect to quantities of +net proved developed oil and natural gas reserves and changes in those reserves +for the years ended December 31, 1998, 1999 and 2000. The quantities were +estimated by an independent petroleum engineer. The Company's proved developed +oil and natural gas reserves are located entirely within the United States. +RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES +YEAR ENDED DECEMBER 31, +-------------------------------- +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Oil and natural gas sales................................... $ 5,641 $ 6,834 $ 13,619 +Gain on sale of oil and natural gas properties.............. 68 9 4 +--------- -------- --------- +5,709 6,843 13,623 +--------- -------- --------- +Costs and expenses: +Lease operating and production costs...................... 1,924 1,720 3,245 +Exploration costs including dry holes and abandonments.... 1,752 780 1,627 +Depreciation, depletion and amortization.................. 4,780 2,674 3,601 +Impairment of oil and natural gas properties.............. 3,816 275 -- +Income tax expense (benefit).............................. (2,231) 533 1,752 +--------- -------- --------- +10,041 5,982 10,225 +--------- -------- --------- +Results of operations for oil and natural gas producing +activities................................................ $ (4,332) $ 861 $ 3,398 +========= ======== ========= +ESTIMATES OF RESERVES AND PRODUCTION PERFORMANCE ARE SUBJECTIVE AND MAY +CHANGE MATERIALLY AS ACTUAL PRODUCTION INFORMATION BECOMES AVAILABLE. +OIL AND NATURAL GAS RESERVE QUANTITIES +OIL (BBLS) GAS (MCF) +---------- --------- +(IN THOUSANDS) +Estimated quantity, January 1, 1998......................... 945 3,788 +Revision in previous estimates.............................. 140 (596) +Extensions, discoveries and other additions................. 146 1,100 +Sales of reserves-in-place.................................. (1) (7) +Production.................................................. (284) (795) +------- -------- +Estimated quantity, January 1, 1999......................... 946 3,490 +Revision in previous estimates.............................. (169) 287 +Extensions, discoveries and other additions................. 683 1,358 +Production.................................................. (255) (1,017) +------- -------- +Estimated quantity, January 1, 2000......................... 1,205 4,118 +Revision in previous estimates.............................. 61 (157) +Extensions, discoveries and other additions................. 134 1,303 +Production.................................................. (275) (1,384) +------- -------- +Estimated quantity, January 1, 2001......................... 1,129 3,880 +======= ======== +F-27 +65 +PATTERSON ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +19. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) -- (CONTINUED) +STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS OF PROVED DEVELOPED OIL AND +NATURAL GAS RESERVES, DISCOUNTED AT 10% PER ANNUM +YEAR ENDED DECEMBER 31, +----------------------------------- +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Future gross revenues..................................... $ 16,451 $ 39,024 $ 48,161 +Future development and production costs................... (7,219) (14,283) (16,270) +Future income tax expense(a).............................. (1,929) (7,392) (8,617) +--------- ---------- ---------- +Future net cash flows..................................... 7,303 17,349 23,274 +Discount at 10% per annum................................. (1,953) (5,267) (6,634) +--------- ---------- ---------- +Standardized measure of discounted future net cash +flows................................................... $ 5,350 $ 12,082 $ 16,640 +========= ========== ========== +--------------- +(a) Future income taxes are computed by applying the statutory tax rate to +future net cash flows less the tax basis of the properties and net +operating loss attributable to oil and gas operations and investment tax +credit carryforwards as of year-end; statutory depletion and tax credits +applicable to future oil and gas-producing activities are also considered +in the income tax computation. +CHANGES IN THE STANDARDIZED MEASURE OF NET CASH FLOWS OF PROVED DEVELOPED OIL +AND GAS RESERVES DISCOUNTED AT 10% PER ANNUM +YEAR ENDED DECEMBER 31, +------------------------------- +1998 1999 2000 +---- ---- ---- +(IN THOUSANDS) +Standardized measure at beginning of year................... $ 8,623 $ 5,350 $ 12,082 +Sales and transfers of oil and gas produced, net of +production costs.......................................... (2,773) (3,696) (7,982) +Net changes in sales price and future production and +development costs......................................... (5,056) 3,177 5,819 +Extensions, discoveries and improved recovery, less related +costs..................................................... 3,018 3,711 4,064 +Sales of minerals-in-place.................................. (9) -- -- +Revision of previous quantity estimates..................... (804) 6,872 1,255 +Accretion of discount....................................... 1,193 709 1,873 +Changes in production rates and other....................... (224) 1,614 (2,435) +Net change in income taxes.................................. 1,382 (5,655) 1,964 +------- --------- --------- +Standardized measure at end of year......................... $ 5,350 $ 12,082 $ 16,640 +======= ========= ========= +F-28 +66 +PATTERSON ENERGY, INC. +SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS +ADDITIONS(1) +------------------------ +CHARGED TO ACQUIRED +BEGINNING COSTS AND THROUGH ENDING +DESCRIPTION BALANCE EXPENSES ACQUISITION DEDUCTIONS(2) BALANCE +----------- --------- ---------- ----------- ------------- ------- +YEAR ENDED DECEMBER 31, 2000 +Deducted from asset accounts: +Allowance for doubtful accounts....... $365 $570 $800 $232 $1,503 +YEAR ENDED DECEMBER 31, 1999 +Deducted from asset accounts: +Allowance for doubtful accounts....... $418 $(38) $ -- $ 15 $ 365 +YEAR ENDED DECEMBER 31, 1998 +Deducted from asset accounts: +Allowance for doubtful accounts....... $378 $ 90 $ -- $ 50 $ 418 +--------------- +(1) Net of recoveries. +(2) Uncollectible accounts written off. +S-1 +67 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, Patterson Energy, Inc. has duly caused this report to be +signed on its behalf by the undersigned, thereunto duly authorized. +PATTERSON ENERGY, INC. +Date: March 1, 2001 By: /s/ CLOYCE A. TALBOTT +------------------------------------ +Cloyce A. Talbott +Chairman of the Board and Chief +Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this +report has been signed by the following persons on behalf of Patterson Energy, +Inc. and in the capacities indicated as of March 1, 2000. +SIGNATURE TITLE +--------- ----- +/s/ CLOYCE A. TALBOTT Chairman of the Board, Chief Executive +-------------------------------------------------------- Officer and Director +Cloyce A. Talbott +(Principal Executive Officer) +/s/ A. GLENN PATTERSON President, Chief Operating Officer and +-------------------------------------------------------- Director +A. Glenn Patterson +/s/ JONATHAN D. NELSON Vice President -- Finance, Chief +-------------------------------------------------------- Financial Officer, Secretary and +Jonathan D. Nelson Treasurer +(Principal Accounting Officer) +/s/ ROBERT C. GIST Director +-------------------------------------------------------- +Robert C. Gist +/s/ SPENCER D. ARMOUR, III Director +-------------------------------------------------------- +Spencer D. Armour, III +/s/ VINCENT A. ROSSI, JR. Director +-------------------------------------------------------- +Vincent A. Rossi, Jr. +/s/ KENNETH R. PEAK Director +-------------------------------------------------------- +Kenneth R. Peak +/s/ STEPHEN J. DEGROAT Director +-------------------------------------------------------- +Stephen J. DeGroat +68 +EXHIBIT INDEX +EXHIBIT +NUMBER DESCRIPTION OF EXHIBIT +------- ---------------------- +2.1 Plan and Agreement of Merger dated October 14, 1993, between +Patterson Energy, Inc., a Texas corporation, and Patterson +Energy, Inc., a Delaware corporation, together with related +Certificates of Merger.(1) +2.2 Agreement and Plan of Merger, dated April 22, 1996 among +Patterson Energy, Inc., Patterson Drilling Company and +Tucker Drilling Company, Inc.(2) +2.2.1 Amendment to Agreement and Plan of Merger, dated May 16, +1996 among Patterson Energy, Inc., Patterson Drilling +Company and Tucker Drilling Company, Inc.(3) +2.3 Stock Purchase Agreement, dated January 5, 1998, among +Patterson Energy, Inc., Spencer D. Armour, III. And Richard +G. Price.(16) +2.4 Stock Purchase Agreement, dated September 17, 1998, among +Lone Star Mud, Inc. and Mark Campbell (shareholder of Tejas +Drilling Fluids, Inc.).(4) +2.5 Asset Purchase Agreement dated as of September 30, 2000 +between Ambar Drilling Fluids LP, LLLP and Ambar, Inc.(5) +2.6 Agreement and Plan of Merger, dated February 4, 2001, by and +between UTI Energy Corp. and Patterson Energy, Inc. +Disclosure schedules for each of the parties to the merger +agreement setting forth exceptions or other information +relating to their respective representations and warrants in +the agreement have not been filed with this exhibit. They +will, however, be made available supplementally to the SEC +upon request.(6) +3.1 Restated Certificate of Incorporation.(7) +3.1.1 Certificate of Amendment to the Certificate of +Incorporation.(8) +3.2 Bylaws.(1) +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(15) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson Energy, Inc. regarding authorized Common Stock and +Preferred Stock.(9) +10.1 Loan and Security Agreement dated December 21, 1999 among +Patterson Drilling Company and Transamerica Equipment +Financial Services Corporation.(17) +10.1.1 Promissory Note dated December 21, 1999 between Patterson +Drilling Company and Transamerica Equipment Financial +Services Corporation.(17) +10.1.2 Corporate Guarantees of Lone Star Mud, Inc. and Patterson +Energy, Inc.(17) +10.2 Aircraft Lease, dated December 20, 2000, (effective January +1, 2001) between Talbott Aviation, Inc. and Patterson +Energy, Inc. +10.3 Participation Agreement, dated October 19, 1994, between +Patterson Petroleum Trading Company, Inc. and BHT Marketing, +Inc.(10) +10.3.1 Participation Agreement dated October 24, 1995, between +Patterson Petroleum Trading Company, Inc. and BHT Marketing, +Inc.(11) +10.4 Crude Oil Purchase Contract, dated October 19, 1994, between +Patterson Petroleum, Inc. and BHT Marketing, Inc.(10) +10.4.1 Crude Oil Purchase Contract, dated October 24, 1995, between +Patterson Petroleum, Inc. and BHT Marketing, Inc.(11) +10.5 Patterson Energy, Inc. 1993 Stock Incentive Plan, as +amended.(12) +10.6 Patterson Energy, Inc. Non-Employee Directors' Stock Option +Plan, as amended.(13) +69 +EXHIBIT +NUMBER DESCRIPTION OF EXHIBIT +------- ---------------------- +10.7 Model Form Operating Agreement.(14) +10.8 Form of Drilling Bid Proposal and Footage Drilling +Contract.(14) +10.9 Form of Turnkey Drilling Agreement.(14) +21.1 Subsidiaries of the registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Petroleum Engineer -- M. Brian +Wallace, P.E. +--------------- +(1) Incorporated herein by reference to Item 27, "Exhibits" to Amendment No. 2 +to Registration Statement on Form SB-2 (File No. 33-68058-FW); filed +October 28, 1993. +(2) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated April 22, 1996 and filed on April 30, 1996. +(3) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated May 16, 1996 and filed on May 22, 1996. +(4) Incorporated by reference to Item 14, "Financial Statements Schedules and +Reports on Form 8-K" to Form 10-K for the year ended December 31, 1998. +(5) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated October 3, 2000 and filed on November 6, 2000. +(6) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated February 4, 2001 and filed February 16, 2001. +(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 1996; filed +August 12, 1996. +(8) Incorporated herein by reference to Item 6. "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 1997; filed +August 14, 1997. +(9) Incorporated herein by reference to Item 16, "Exhibits" to Registration +Statement on Form S-3 filed on December 18, 1996. +(10) Incorporated herein by reference to Item 27, "Exhibits" to Post Effective +Amendment No. 1 to Registration Statement on Form SB-2 (File No. +33-68058-FW); filed on June 21, 1995. +(11) Incorporated by reference to Item 13, "Exhibits and Reports on Form 8-K to +Form 10-KSB for the year ended December 31, 1995. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 333-47917); filed March 13, 1998. +(13) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471); filed November 4, 1997. +(14) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW); filed with the Securities and Exchange +Commission on August 30, 1993. +(15) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on Form 8-A filed on January 14, 1997. +(16) Incorporated herein by reference to Item 16, "Exhibits" to Registration +Statement on Form S-3 filed on January 5, 1998. +(17) Incorporated by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Form 10-K for the year ended December +31, 1999. \ No newline at end of file diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/filing_metadata.csv b/raw/filings/0000889900/2000/0000950134-01-001886/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..a2b296ffc40c517e96ddf5c174b312a41d650e71 --- /dev/null +++ b/raw/filings/0000889900/2000/0000950134-01-001886/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K405,2001-03-02,2000-12-31,2001-03-02T05:00:00.000Z,0000950134-01-001886,d84623e10-k405.txt,"FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000",268610,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013401001886/d84623e10-k405.txt,https://www.sec.gov/Archives/edgar/data/889900/000095013401001886/,2000,2000,1 diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/item1.txt b/raw/filings/0000889900/2000/0000950134-01-001886/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/item13.txt b/raw/filings/0000889900/2000/0000950134-01-001886/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..b46b29509b25171713c6e4ec449c2d0eb9dfe4a2 --- /dev/null +++ b/raw/filings/0000889900/2000/0000950134-01-001886/item13.txt @@ -0,0 +1,5 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +34 +35 \ No newline at end of file diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/item9a.txt b/raw/filings/0000889900/2000/0000950134-01-001886/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/rp_note.txt b/raw/filings/0000889900/2000/0000950134-01-001886/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..a366de83e46141d8c252cc55330549460b838b49 --- /dev/null +++ b/raw/filings/0000889900/2000/0000950134-01-001886/rp_note.txt @@ -0,0 +1,25 @@ +17. RELATED PARTY TRANSACTIONS +Use of Assets -- The Company leases a 1981 Beech King-Air 90 airplane owned +by an affiliate of the Company's Chairman of the Board/Chief Executive Officer. +Under the terms of the lease, the Company pays a monthly rental of $9,200 and +its proportionate share of the costs of fuel, insurance, taxes and maintenance +of the aircraft. The Company paid approximately $211,495, $222,583 and $193,769 +for the lease of the airplane during 1998, 1999 and 2000, respectively. +Contract Drilling Services -- The Company provided contract drilling +services to an affiliated company during 1999 with related revenues of +approximately $275,642. +Sales of Oil -- An affiliate acted as the first purchaser of oil produced +from leases operated by the Company during 1998 and 1999. Sales of oil to that +entity, both royalty and working interest (including the Company) were +approximately $8.1 million and $8.4 million for 1998 and 1999, respectively. +There were no sales of oil to that entity in 2000. +Joint Operation of Oil and Natural Gas Properties -- The Company operates +certain oil and natural gas properties in which the Chairman of the Board/Chief +Executive Officer, the President/Chief Operating Officer and other persons or +entities related to the Company purchased a joint interest ownership with the +Company and other industry partners. The Company made oil and natural gas +production payments (net of royalty) of $10.5 million, $6.1 million and $13.4 +million from these properties in 1998, 1999 and 2000, respectively, to the +aforementioned persons or entities. These persons or entities reimbursed the +Company for joint operating costs of $7.4 million, $5.9 million and $8.0 million +in 1998, 1999 and 2000, respectively. \ No newline at end of file diff --git a/raw/filings/0000889900/2000/0000950134-01-001886/rpt_disclosure.txt b/raw/filings/0000889900/2000/0000950134-01-001886/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/filing.txt b/raw/filings/0000889900/2001/0000950134-02-002237/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..15ad394bd5dd7352416339fafd0b0fc6693a91f4 --- /dev/null +++ b/raw/filings/0000889900/2001/0000950134-02-002237/filing.txt @@ -0,0 +1,3239 @@ +10-K +1 +d94131e10-k.txt +FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2001 +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +UNITED STATES SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +--------------------- +FORM 10-K +--------------------- +(MARK ONE) +[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF +1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 +OR +[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT +OF 1934 FOR THE TRANSITION PERIOD FROM TO +COMMISSION FILE NUMBER 0-22664 +--------------------- +PATTERSON-UTI ENERGY, INC. +(Exact name of registrant as specified in its charter) +DELAWARE 75-2504748 +(State or other jurisdiction of (I.R.S. Employer Identification No.) +incorporation or organization) +P.O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS 79549 +(Address of principal executive offices) (Zip Code) +--------------------- +Registrant's telephone number, including area code: (915) 574-6300 +--------------------- +Securities Registered Pursuant to 12(b) of the Act: None +Securities Registered Pursuant to 12(g) of the Act: +(TITLE OF CLASS) +Common Stock, $.01 Par Value +Indicate by check mark whether the registrant (1) has filed all reports +required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the +registrant was required to file such reports), and (2) has been subject to such +filing requirements for the past 90 days. Yes [X] No [ ] +Indicate by check mark if disclosure of delinquent filers pursuant to Item +405 of the Regulation S-K is not contained herein, and will not be contained, to +the best of the registrant's knowledge, in definitive proxy or information +statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K [ ] +The aggregate market value of the voting and non-voting common equity held +by non-affiliates of the registrant as of March 18, 2002 was $2,020,682,056, +based upon the average bid and asked prices of $28.29 and $28.56, respectively, +on the Nasdaq National Market. +As of March 18, 2002, the registrant had outstanding 77,613,794 shares of +common stock, $.01 par value, its only class of voting stock. +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +FORWARD LOOKING STATEMENTS +Patterson-UTI Energy, Inc. ("Patterson-UTI" or the "Company") from time to +time makes written or oral forward-looking statements, including statements +contained in our filings with the SEC, press releases and reports to +stockholders. These forward-looking statements are made pursuant to the "safe +harbor" provisions of the Private Securities Litigation Reform Act of 1995. +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. Readers are +cautioned that such forward-looking statements should be read in conjunction +with our disclosures under the heading: "Cautionary Statement for Purposes of +the 'Safe Harbor' Provisions of the Private Securities Litigation Reform Act of +1995" beginning on page 13. +PART I +ITEMS 1 AND 2. BUSINESS AND PROPERTIES. +OVERVIEW +Patterson-UTI is the second largest operator of land-based drilling rigs in +North America. Formed in 1978 and reincorporated in 1993 as a Delaware +corporation, we focus our contract drilling operations in: +- Texas, +- New Mexico, +- Oklahoma, +- Louisiana, +- Mississippi, +- Utah, and +- Western Canada (Alberta, British Columbia and Saskatchewan). +We currently have a drilling fleet of 319 drilling rigs, of which 287 +operated in 2001. A drilling rig includes the structure, power source and +machinery necessary to cause a drill bit to penetrate rock to a depth desired by +the customer. +We provide drilling fluids, completion fluids and related services to oil +and natural gas producers in the Permian Basin of West Texas and Southeast New +Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast regions of Texas and +Louisiana, and the Gulf of Mexico. Drilling and completion fluids are used by +oil and natural gas operators during the drilling process to control pressure +when drilling oil and natural gas wells. We also provide pressure pumping +services in the Appalachian Basin. These services consist primarily of well +stimulation and cementing for completion of new wells and remedial work on +existing wells. To a lesser extent, we are engaged in the development, +exploration, acquisition and production of oil and natural gas. Our oil and +natural gas operations are not financially material and do not warrant +disclosure as a business segment. +PATTERSON/UTI MERGER +Patterson Energy, Inc. ("Patterson") and UTI Energy Corp. ("UTI") +consummated a merger on May 8, 2001, with Patterson as the surviving entity. +That transaction was a merger of equals and was treated as a reorganization +within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as +amended, and accounted for as a pooling of interests for financial accounting +purposes. Historical financial statements and related financial and statistical +data contained in this Report have been restated to provide for the retroactive +effect of the merger. At the time of the merger, the name of Patterson Energy, +Inc. was changed to "Patterson-UTI Energy, Inc." +2 +INDUSTRY SEGMENTS +Our revenues, operating profits and identifiable operating assets are +primarily attributable to three industry segments: +- contract drilling, +- drilling and completion fluids services, and +- pressure pumping services. +With respect to these three segments: +- the contract drilling segment had an operating loss in 1999 and operating +profits in 2000 and 2001, +- the drilling and completion fluids segment had operating losses in 1999 +and 2000, and an operating profit in 2001, and +- the pressure pumping segment had operating profits in 1999, 2000 and +2001. +See "Management's Discussion and Analysis of Financial Condition and +Results of Operations" and Note 14 of Notes to Consolidated Financial Statements +included as a part of Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +CONTRACT DRILLING OPERATIONS +GENERAL. We market our contract drilling services to major and independent +oil and natural gas producers and operators. We currently own 319 drilling rigs +which are located in the following regions: +- 257 in Texas and New Mexico(1) +- 41 in Oklahoma, +- five in Utah, and +- 16 in Western Canada. +--------------- +(1) 144 in West Texas and New Mexico, 53 in South Texas, 39 in East Texas +and 21 in North Central Texas, +Of our drilling rigs, 33 are SCR electric rigs and 286 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. Our drilling rigs have rated maximum depth capabilities +ranging from 4,000 feet to 30,000 feet. +Drilling rigs are typically equipped with: +- engines, +- drawworks or hoists, +- derricks or masts, +- pumps to circulate the drilling fluid, +- blowout preventers, +- drill string (pipe), and +- other related equipment. +Over time, many of the components on a drilling rig are replaced or +rebuilt. We spend significant funds each year on an ongoing program of modifying +and upgrading our drilling rigs to ensure that our drilling equipment is well +maintained and competitive. +3 +Depth of the well and drill site conditions are the principal factors in +determining the size of drilling rig used for a particular job. Our drilling +rigs are utilized for both exploratory and developmental drilling and can be +used for either vertical or horizontal drilling. +Our contract drilling operations depend on the availability of: +- drill pipe, +- bits, +- replacement parts and other related rig equipment, +- fuel, and +- qualified personnel, +some of which have been in short supply from time to time. +DRILLING CONTRACTS. Most of our drilling contracts are with established +customers and are obtained on a competitive bid or negotiated basis. Generally, +the contracts are entered into for short-term periods and cover the drilling of +a single well or a series of wells with the terms and rates depending upon the +nature and duration of the work, the equipment and services supplied and other +matters. +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 subject to termination by the +customer on short notice, usually upon payment of a fee. We generally indemnify +our customers against claims by our employees and claims arising from surface +pollution caused by spills of fuel, lubricants and other solvents within our +control. The customers generally indemnify us against claims arising from other +surface and subsurface pollution, except claims arising from our own 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 bids +for each contract depend upon: +- the location, depth and anticipated complexity of the well, +- the on-site drilling conditions, +- the equipment to be used, +- our estimate of the risks involved, +- the estimated duration of the work to be performed, +- the 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, also known as the operator. The customer then supervises the drilling +of the contracted well. Our compensation is based on a negotiated rate per day +during the period the drilling rig is utilized. We generally receive a lower +rate when the drilling rig is moving, or when drilling operations are +interrupted or restricted by adverse weather conditions or other conditions +beyond our control. In addition, daywork contracts typically provide for a lump +sum fee for the mobilization and demobilization of the drilling rig. +FOOTAGE CONTRACTS +Under footage contracts, we contract to drill a well to a certain depth +under specified conditions for a fixed price per foot. The customer provides +drilling fluids, casing, cementing and well design expertise. These 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, then we have the opportunity to improve our +4 +margins over those that would be attainable under a daywork contract. Margins +are reduced and losses may be incurred if the well requires more days to drill +than estimated. Footage contracts generally contain greater risks for a drilling +contractor than daywork contracts. Under these contracts, the drilling +contractor assumes certain risks associated with loss of hole from fire, +blowouts and other risks. +TURNKEY CONTRACTS +Under turnkey contracts, we contract to drill a well to a certain depth +under specified conditions for a fixed fee. In a turnkey arrangement, we are +required to bear the costs of services, supplies and equipment beyond those +typically provided under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion fluids, casing, +cementing and the technical well design and engineering services during the +drilling process. We would also assume certain risks associated with drilling +the well such as fires, blowouts, cratering of the well bore and other such +risks. Compensation occurs only when the agreed scope of the work has been +completed which requires us to make significant 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 margins 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, margins +can be significantly reduced and losses incurred if complications or delays +occur during the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of drilling contracts: +daywork, footage and turnkey. +The following table sets forth the approximate percentage of our drilling +revenues attributable to daywork, footage and turnkey contracts for each of the +last three years: +YEAR ENDED DECEMBER 31, +------------------------- +TYPE OF CONTRACT 2001 2000 1999 +---------------- ----- ----- ----- +Daywork..................................................... 93% 65% 54% +Footage..................................................... 3 24 26 +Turnkey..................................................... 4 11 20 +CONTRACT DRILLING ACTIVITY. The following table sets forth certain +information regarding our contract drilling activity for each of the last three +years: +YEAR ENDED DECEMBER 31, +----------------------- +2001 2000 1999 +---- ---- ---- +Number of wells drilled..................................... 2,869 2,649 1,519 +Average rigs owned.......................................... 302 263 231 +Average rig utilization rate(1)............................. 70% 66% 43% +--------------- +(1) Rig utilization is based on a 365-day year for rigs owned during 1999 and +2001, and a 366-day year for rigs owned in 2000. A rig is utilized when it +is operating or being moved, assembled or dismantled under contract. +DRILLING RIGS AND RELATED EQUIPMENT. The following table provides certain +information concerning our drilling rigs as of December 31, 2001: +DEPTH RATING (FT.) MECHANICAL ELECTRIC +------------------ ---------- -------- +4,000 to 9,999.............................................. 52 -- +10,000 to 11,999............................................ 67 2 +12,000 to 14,999............................................ 114 6 +15,000 to 30,000............................................ 53 25 +--- -- +Totals............................................ 286 33 +=== == +5 +At December 31, 2001, we owned 234 trucks and 271 trailers used to rig +down, transport and rig up our drilling rigs. This reduces Patterson-UTI's +dependency upon third parties for these services and enhances the efficiency of +our contract drilling operations particularly in periods of high drilling rig +utilization. +Most repair work and overhaul of our drilling rig equipment is performed at +our yard facilities located in Texas, New Mexico, Oklahoma and Western Canada. +DRILLING AND COMPLETION FLUIDS OPERATIONS +GENERAL. We provide drilling fluids, completion fluids and related +services to oil and natural gas producers in the Permian Basin of West Texas and +Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast regions +of Texas and Louisiana and the Gulf of Mexico. We serve our offshore customers +through seven stockpoints located along the Gulf of Mexico in Texas and +Louisiana, and our land-based customers through seven stockpoints in Louisiana, +Texas, Oklahoma and New Mexico. +DRILLING FLUIDS. Our product sales are supported by a technical service +organization dedicated to product application on the customer's wellsite. +Drilling fluid products and systems are used to cool and lubricate the drill bit +during drilling operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole and maintain the +stability of the wellbore. Technical services are provided to ensure that the +products and systems are applied effectively to optimize drilling operations. +COMPLETION FLUIDS. After a well is drilled it undergoes the completion +process wherein the well casing is set and cemented in place. At that point, the +drilling fluid services are complete, and the drilling fluids are circulated out +of the well and replaced with completion fluids. Completion fluids, also known +as clear brine fluids, are solids-free, clear salt solutions that have high +specific gravities. Combined with a range of specialty chemicals, these fluids +are used by operators to control bottom-hole pressures and to meet a well's +specific corrosion, inhibition, viscosity, and fluid loss requirements during +the completion and workover phases. +RAW MATERIALS. Our drilling and completion fluids operations depend on the +availability of the following raw materials: +DRILLING COMPLETION +-------- ---------------- +barite calcium chloride +bentonite calcium bromide +zinc bromide +We obtain these raw materials through purchases made on the spot market and +supply contracts with producers of these raw materials. +BARITE GRINDING FACILITY. We own and operate a barite grinding facility +equipped with two barite grinding mills located in Houma, Louisiana. We believe +the ability to process our own barite is critical to being competitive on the +Gulf Coast and in the Gulf of Mexico since barite accounts for a substantial +portion of the dollar volume for drilling fluids jobs in both of these areas. +Our grinding facility allows us to grind raw barite into the powder additive +used in producing drilling fluids. Owning this facility reduces our dependence +upon third parties in our supply of barite. Without the grinding mills we would +be required to purchase processed barite from third parties, including some of +our competitors, which could result in higher production costs and less +efficient operations. +OTHER EQUIPMENT. We own 28 trucks and 118 trailers and lease another 36 +trucks used to transport drilling and completion fluids and related equipment. +PRESSURE PUMPING OPERATIONS +GENERAL. We provide pressure pumping services 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. Most wells +drilled in the Appalachian Basin require some form of fracturing or other +6 +stimulation to enhance the flow of oil and natural gas which is accomplished by +pumping fluids under pressure into the well bore. Generally, Appalachian Basin +wells require cementing services before production commences. Cementing is the +process of inserting material between the wall of the well bore and the casing +to center and stabilize the casing. +EQUIPMENT. Patterson-UTI continuously maintains its pressure pumping +equipment. Virtually all of the pressure pumping equipment is in use on a +regular basis. As of December 31, 2001, Patterson-UTI operated the following +pressure pumping equipment: +- 16 cement pumper trucks, +- 22 fracturing pumper trucks, +- 19 nitrogen pumper trucks, +- 11 blender trucks, +- 8 bulk acid trucks, +- 24 bulk cement trucks, +- 6 bulk nitrogen trucks, +- 18 bulk sand trucks, and +- 6 connection trucks. +CUSTOMERS +The customers of each of our three business segments are producers or +operators of oil and natural gas. Our customer base includes both major and +independent oil and natural gas companies within the oil and gas industry. +During 2001, no single customer accounted for 10% or more of our consolidated +operating revenues. +COMPETITION +CONTRACT DRILLING AND PRESSURE PUMPING BUSINESSES. Our land drilling and +pressure pumping businesses are intensely competitive due to the fact that the +supply of available land drilling rigs and pressure pumping equipment exceeds +the demand for those rigs and 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. +Patterson-UTI believes 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 addition, some of our +competitors have greater financial resources than we do which may enable them +to: +- better withstand industry downturns, +- compete more effectively on the basis of price, and +- acquire existing rigs or equipment or build new rigs or 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. +DRILLING AND COMPLETION FLUIDS BUSINESS. The drilling and completion +fluids services industry is highly competitive. Price is generally the most +important competitive factor in the industry. Other competitive factors include +the availability of chemicals and experienced personnel, the reputation of the +fluids services provider in the drilling industry and our relationship with +existing customers. Some of our competitors have substantially greater resources +and longer operating histories than we have. We believe that competition for +drilling and completion fluids service contracts will continue to be intense. +7 +GOVERNMENT AND ENVIRONMENTAL REGULATION +Patterson-UTI's operations and facilities are subject to numerous state, +federal and foreign (Canadian) laws, rules and regulations, including, but +limited to: +- drilling of oil and gas wells, +- containment and disposal of hazardous materials, oilfield waste, other +waste materials and acids, +- use of underground storage tanks, and +- use of underground injection wells. +To date, we have not been required to expend significant resources in order +to satisfy applicable environmental laws and regulations. We do not anticipate +any material capital expenditures for environmental control facilities or +extraordinary expenditures to comply with compliance 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 for noncompliance. +Our business is generally affected by political developments and by +federal, state, foreign and local laws and regulations, which relate to the oil +and natural gas industry. The adoption of laws and regulations affecting the oil +and natural gas industry for economic, environmental and other policy reasons +could increase costs relating to drilling and production. They could have an +adverse effect on our operations. Several state and federal environmental laws +and regulations currently apply to our operations and may become more stringent +in the future. +We have utilized operating and disposal practices that were or are +currently 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 operated by us or our predecessors in interest. In addition, +some of these properties have been operated by third parties over whom we have +no control either as to such entities' treatment of hydrocarbon and other +materials or the manner in which such materials may have been disposed of or +released. +The federal Comprehensive Environmental Response Compensation and Liability +Act of 1980, 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 and comparable state +statutes govern the disposal of "hazardous wastes." Although CERCLA currently +excludes petroleum from the definition of "hazardous substances," and the +Resource Conservation and Recovery Act also excludes certain classes of +exploration and production wastes from regulation, such exemptions by Congress +under both CERCLA and the Resource Conservation and Recovery Act may be deleted, +limited or modified in the future. If such changes are made to CERCLA and/or the +Resource Conservation and Recovery Act, 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 +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 +8 +damages. Penalties may also be imposed for violation of federal safety, +construction and operating regulations, and for failure to report a spill or to +cooperate fully in a clean-up. +The Oil Pollution Act also expands the authority and capability of the +federal government to direct and manage oil spill clean-up and operations, and +requires operators to prepare oil spill response plans in cases where it can +reasonably be expected that substantial harm will be done to the environment by +discharges on or into navigable waters. We have spill prevention control and +countermeasure plans in place for our oil and natural gas properties in each of +the areas in which we operate and for each of the stockpoints operated by our +drilling and completion fluids business. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a +responsible party, such as Patterson-UTI, 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 and various state and +local laws impose certain air quality requirements on Patterson-UTI. Amendments +to the Clean Air Act revised the definition of "major source" such that +emissions from both wellhead and associated equipment involved in oil and +natural gas production may be added to determine if a source is a "major +source." As a consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting process may +require capital expenditures in order to comply with permit limits. +RISKS AND INSURANCE +Our operations are subject to the many hazards inherent in the drilling +business, including: +- accidents at the work location, +- blow-outs, +- cratering, +- fires, and +- explosions. +These hazards could cause: +- personal injury or death, +- suspension of drilling operations, or +- serious damage or destruction of the equipment involved and, in addition +to environmental damage, could cause substantial damage to producing +formations and surrounding areas. +Damage to the environment, including property contamination in the form of +either soil or ground water contamination, could also result from our +operations, particularly through: +- oil or produced water spillage, +- natural gas leaks, and +- extensive, uncontrolled fires. +In addition, we could become subject to liability for reservoir damages. +The occurrence of a significant event, including pollution or environmental +damages, could materially affect our operations and financial condition. +9 +As a protection against operating hazards, we maintain insurance coverage +we believe to be adequate, including: +- all-risk physical damages, +- employer's liability, +- commercial general liability, and +- workers compensation insurance. +We believe that we are adequately insured for public liability and property +damage to others with respect to our operations. However, such insurance may not +be sufficient to protect us against liability for all consequences of: +- personal injury, +- well disasters, +- extensive fire damage, +- damage to the environment, or +- other hazards. +We also carry insurance to cover major physical damage to or loss of our +drilling rigs. However, we do not carry insurance against loss of earnings +resulting from such damage or loss. In view of the difficulties that may be +encountered in renewing such insurance at reasonable rates, no assurance can be +given that: +- we will be able to maintain the type and amount of coverage that we +believe to be adequate at reasonable rates, or +- any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain of the risks. These indemnity +agreements typically require our customers to hold us harmless in the event of +loss of production or reservoir damage. These contractual indemnifications may +not be supported by adequate insurance maintained by the customer. +EMPLOYEES +We employed approximately 5,250 full-time persons (230 office personnel and +5,020 field personnel) at December 31, 2001. The number of field employees +fluctuates depending on the current and expected demand for the services we +provide. We consider our employee relations to be satisfactory. None of our +employees is represented by a union. +SEASONALITY +Seasonality does not significantly affect our overall operations. However, +our pressure pumping division in Appalachia and our drilling operations in +Canada are subject to slow periods of activity during the spring thaw. In +addition, our drilling operations in Canada are subject to slow periods of +activity during the fall. +RAW MATERIALS AND SUBCONTRACTORS +Patterson-UTI uses many suppliers of raw materials and services. These +materials and services have been and continue to be available. We also utilize +numerous independent subcontractors from various trades. +INCORPORATION BY REFERENCE +The various factors disclosed under the caption "Cautionary Statement for +Purposes of the "Safe Harbor" Provisions of the Private Litigation Reform Act of +1995," beginning on page 13 of this Report, are +10 +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 +these Items 1 and 2. +CORPORATE HEADQUARTERS, FIELD OFFICES AND OTHER FACILITIES +Our corporate headquarters are located in Snyder, Texas. We also have a +number of offices, yard 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 (915) 574-6300. There are a +number of improvements at our headquarters, including: +- an office building with approximately 16,000 square feet, with an +additional building currently under construction that will add another +18,000 square feet of office space and storage, +- a shop facility with approximately 7,000 square feet used for drilling +equipment repairs and metal fabrication, +- a truck shop facility with approximately 10,000 square feet used to +maintain, overhaul and repair our truck fleet, +- an engine shop facility with approximately 20,000 square feet used to +overhaul and repair the engines used to power our drilling rigs, and +- an open-ended metal storage facility with approximately 10,200 square +feet. +We have regional administrative offices, yard and stockpoint facilities in +many of the areas in which we operate. The facilities are primarily used to +support the day-to-day operations, including the repair and maintenance of +equipment as well as the storage of equipment, inventory and supplies and to +facilitate administrative responsibilities and sales. +CONTRACT DRILLING OPERATIONS +Our drilling operations are supported by several administrative offices and +yard facilities located throughout our areas of operations including: +- Texas, +- New Mexico, +- Oklahoma, +- Utah, and +- Western Canada. +DRILLING AND COMPLETION FLUIDS +Our drilling and completion fluids are supported by several administrative +offices and stockpoint facilities located throughout our areas of operations +including: +- Texas, +- Louisiana, +- New Mexico, and +- Oklahoma. +11 +PRESSURE PUMPING +Our pressure pumping operations are supported by several offices and yard +facilities located throughout our areas of operations including: +- Pennsylvania, +- Ohio, +- Kentucky, and +- New York. +We own our headquarters in Snyder and lease the majority of our other +facilities. We do not believe that any of these other facilities are +individually material to our operations. We believe that our existing facilities +are suitable and adequate to meet our needs. +ITEM 3. LEGAL PROCEEDINGS. +Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc. +("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson +Petroleum LP and Patterson Drilling Company LP, in the Circuit Court, Rankin +County, Mississippi, Case No. 2002-18, on January 28, 2002. The lawsuit relates +to a letter agreement entered into in July 2000 between Patterson Petroleum and +Westfort concerning the drilling of a daywork well in Mississippi. This lawsuit +was filed by Westfort after Patterson Petroleum made demand on Westfort for +payment of the contract drilling services. +In this lawsuit, Westfort alleges breach of contract, fraud and negligence +causes of action. Westfort seeks alleged monetary damages, the return of shares +of Westfort stock, unspecified damages from alleged lost profits, lost use of +income stream and additional operating expenses, along with alleged punitive +damages to be determined by the jury, but not less than 25% of Patterson's net +worth. We intend to vigorously contest the allegations made by Westfort and +assert claims against Westfort, including for the monies owed Patterson under +the letter agreement in the amount of approximately $5,075,000. +In addition to the Westfort lawsuit, we are party to various legal +proceedings arising in the normal course of our business. We do not believe that +the outcome of these proceedings, either individually or in the aggregate, will +have a material adverse effect on our financial condition. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. +None. +12 +CAUTIONARY STATEMENTS FOR PURPOSES OF THE "SAFE HARBOR" +PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 +We include the following cautionary statement in accordance with the "safe +harbor" provisions of the Private Securities Litigation Reform Act of 1995 for +any forward-looking statement made by us, or on our behalf. The factors +identified in this cautionary statement are important factors (but not +necessarily all of the important factors) that could cause actual results to +differ materially from those expressed in any forward-looking statement made by +us, or on our behalf. Where any such forward-looking statement includes a +statement of the assumptions or bases underlying such forward-looking statement, +we caution that, while we believe such assumptions or bases to be reasonable and +make them in good faith, assumed facts or bases almost always vary from actual +results. The differences between assumed facts or bases and actual results can +be material, depending upon the circumstances. +Where, in any forward-looking statement, Patterson-UTI, or our management, +expresses an expectation or belief as to the future results, such expectation or +belief is expressed in good faith and believed to have a reasonable basis. +However, there can be no assurance that the statement of expectation or belief +will result, or be achieved or accomplished. Taking this into account, the +following are identified as important risk factors that could cause actual +results to differ materially from those expressed in any forward-looking +statement made by, or on behalf of, Patterson-UTI: +PATTERSON-UTI IS DEPENDENT ON THE OIL AND NATURAL GAS INDUSTRY AND MARKET PRICES +FOR OIL AND NATURAL GAS. DECLINES IN OIL AND NATURAL GAS PRICES HAVE ADVERSELY +AFFECTED OUR OPERATIONS. +Our revenue, profitability and rate of growth are substantially dependent +upon prevailing prices for oil and natural gas. In recent years, oil and natural +gas prices and, therefore, the level of drilling, exploration, development and +production, have been extremely volatile. Prices are affected by: +- market supply and demand, +- international military, political and economic conditions, and +- the ability of the Organization of Petroleum Exporting Countries, +commonly known as OPEC, to set and maintain production and price targets. +All of these factors are beyond our control. Beginning in the third quarter +of 2001 and continuing through the date of this report, commodity price +uncertainty has adversely affected our operations. We expect oil and natural gas +prices to continue to be volatile and to affect our financial condition and +operations and ability to access sources of capital. +INDUSTRY CONDITIONS FOR CONTRACT DRILLING SERVICES HAVE BEEN POOR FOR MUCH OF +THE TIME SINCE 1982. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 due to higher oil and natural gas +prices. The increase in demand returned, beginning in mid-1999 and continued +through the second quarter of 2001. However, except for those periods and other +occasional upturns, the market for onshore contract drilling services and the +other services we provide has generally been depressed since 1982, when the +number of operable land drilling rigs was at record levels. Since this time +there have been substantially more drilling rigs available than necessary to +meet demand in most operational and geographic segments of the North American +land drilling industry. As a result, drilling contractors have had difficulty +sustaining profit margins. +In addition to adverse effects that future declines in demand could have on +Patterson-UTI, ongoing factors which could adversely affect utilization rates +and pricing, even in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +- movement of drilling rigs from region to region, +- reactivation of land-based drilling rigs, or +- new construction of drilling rigs. +13 +We cannot predict either the future level of demand for our contract +drilling services or future conditions in the oil and natural gas contract +drilling business. +SHORTAGES OF DRILL PIPE, REPLACEMENT PARTS AND OTHER RELATED RIG EQUIPMENT +ADVERSELY AFFECTS PATTERSON-UTI'S 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 caused the price of these items to increase +significantly and required that orders for the items be placed well in advance +of expected use. These price increases and delays in delivery caused us to +substantially increase capital expenditures in our contract drilling segment. +Severe shortages could impair our ability to operate our drilling rigs. +THE VARIOUS BUSINESS SEGMENTS IN WHICH WE OPERATE ARE HIGHLY COMPETITIVE WITH +EXCESS CAPACITY WHICH MAY ADVERSELY AFFECT OUR OPERATING RESULTS. +Our land drilling and pressure pumping businesses are intensely competitive +due to the fact that the supply of available land drilling rigs and pressure +pumping equipment exceeds the demand for those rigs and 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. +Patterson-UTI believes 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 addition, some of our +competitors have greater financial resources than we do which may enable them +to: +- better withstand industry downturns, +- compete more effectively on the basis of price, and +- acquire existing rigs or equipment or build new rigs or equipment. +In recent years, many drilling and pressure pumping companies have +consolidated or merged with other companies. Although this consolidation has +decreased the total number of competitors, we believe the competition for +drilling and pressure pumping services will continue to be intense. +The drilling and completion fluids services industry is highly competitive. +Price is generally the most important competitive factor in the industry. Other +competitive factors include the availability of chemicals and experienced +personnel, the reputation of the fluids services provider in the drilling +industry and our relationship with existing customers. Some of our competitors +have substantially greater resources and longer operating histories than we +have. We believe that competition for drilling and completion fluids service +contracts will continue to be intense. +LABOR SHORTAGES ADVERSELY AFFECT OUR OPERATING RESULTS. +During periods of increased demand for contract drilling services, the +industry experiences shortages of qualified drilling rig personnel. During these +periods, our ability to attract and retain sufficient qualified personnel to +market and operate our drilling rigs is adversely affected. Labor shortages also +cause wage increases, which impact our operating margins. +CONTINUED GROWTH OF PATTERSON-UTI THROUGH RIG ACQUISITION IS NOT ASSURED. +We have increased our drilling rig fleet over the past several years +through mergers and acquisitions. In May 2001, UTI merged with Patterson in a +so-called "merger of equals." The combination of the two companies doubled the +number of our drilling rigs. The land drilling industry has experienced +significant 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. +14 +There can be no assurance that we would: +- have sufficient capital resources to complete additional acquisitions, +- successfully integrate acquired operations and assets, +- be able to manage effectively the growth and increased size, +- be successful in deploying idle or stacked rigs, +- be able to maintain the crews and market share attributable to operating +drilling rigs acquired, or +- be successful in improving our financial condition, results of operation, +business or prospects in any material manner as a result of any completed +acquisition. +We may incur substantial indebtedness to finance future acquisitions and +also may issue equity securities or convertible securities in connection with +any such acquisitions. Debt service requirements could represent a significant +burden on our results of operations and financial condition and the issuance of +additional equity could be dilutive to our existing stockholders. Also, +continued growth could strain our management, operations, employees and +resources. +THE NATURE OF OUR BUSINESS OPERATIONS PRESENTS INHERENT RISKS OF LOSS THAT, IF +NOT INSURED OR INDEMNIFIED AGAINST COULD ADVERSELY AFFECT PATTERSON-UTI'S +OPERATING RESULTS. +Our operations are subject to many hazards inherent in the contract +drilling, pressure pumping and drilling and completion fluids businesses, which +in turn could cause personal injury or death, work stoppage or serious damage to +our equipment. Our operations could also cause environmental and reservoir +damages. We maintain insurance coverage and have indemnification agreements with +many of our customers. However, there is no assurance that such insurance or +indemnification agreements would adequately protect Patterson-UTI against +liability from all consequences of the hazards. Additionally, there can be no +assurance that insurance would be available to cover any or all of these risks, +or, even if available, that insurance premiums or other costs would not rise +significantly in the future, so as to make such insurance prohibitive. +VIOLATIONS OF ENVIRONMENTAL LAWS AND REGULATIONS COULD MATERIALLY ADVERSELY +AFFECT PATTERSON-UTI OPERATING RESULTS. +The drilling of oil and natural gas wells is subject to various state, +federal and foreign laws, rules and regulations. The cost to Patterson-UTI of +compliance with these laws and regulations could be substantial. Failure to +comply with these requirements could subject Patterson-UTI 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. Patterson-UTI, as an owner and operator +of land-based drilling rigs may be deemed to be a responsible party under +federal law. Our operations and facilities are subject to numerous state and +federal environmental laws, rules and regulations, including, without +limitation, laws concerning the containment and disposal of hazardous +substances, oil field waste and other waste materials, the use of underground +storage tanks and the use of underground injection wells. We generally try to +require our customers to contractually assume responsibility for compliance with +environmental regulations, however, we are not always successful in shifting all +of those risks, nor is there any assurance that the applicable customer will be +financially able to bear those risks assumed. +SOME OF OUR CONTRACT DRILLING SERVICES ARE DONE UNDER TURNKEY AND FOOTAGE +CONTRACTS, WHICH ARE FINANCIALLY RISKY. +A portion of our contract drilling is done under turnkey contracts and +footage contracts, which involve significant risks. Under turnkey drilling +contracts, we contract to drill a well to a certain depth under specified +conditions for a fixed price. Under footage contracts, we contract to drill a +well to a certain depth under specified conditions at a fixed price per foot. +The risk to us under these types of drilling contracts are greater than on a +well drilled on a daywork basis. Unlike daywork contracts, we must bear the cost +of performing +15 +drilling services until the target depth is reached. We must also make +significant up-front working capital commitments prior to receiving payment. In +addition, we must assume most of the risk associated with the drilling +operations, generally assumed by the operator of the well on a daywork contract, +including blowouts, loss of hole from fire, machinery breakdowns and abnormal +drilling conditions. Accordingly, if severe drilling problems are encountered in +drilling wells under such contracts, we could suffer substantial losses. +ANTI-TAKEOVER MEASURES IN OUR CHARTER DOCUMENTS AND UNDER STATE LAW COULD +DISCOURAGE AN ACQUISITION OF PATTERSON-UTI AND THEREBY AFFECT THE RELATED +PURCHASE PRICE. +Patterson-UTI, as a Delaware corporation, is 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 of Patterson-UTI +may find it more difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our securities of +certain opportunities to sell or otherwise dispose of the securities at +above-market prices pursuant to any such transactions. +WE HAVE PAID NO DIVIDENDS ON OUR COMMON STOCK AND HAVE NO PLANS TO PAY +DIVIDENDS. +We have not declared or paid cash dividends on our common shares in the +past. We do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. The terms of our existing credit facility limit the +payment of dividends without the prior written consent of the lenders. +16 +PART II +ITEM 5. MARKET FOR OUR COMMON SHARES AND RELATED STOCKHOLDER MATTERS. +Our common stock, par value $0.01 per share is publicly traded on the +Nasdaq National Market and is quoted under the symbol "PTEN." In November 2001, +our common stock was added to the S&P MidCap 400 Index. Our common stock is also +included in several other market indexes. +The following table sets forth the high and low closing prices of our +common shares for the periods indicated: +HIGH LOW +-------- -------- +2001: +First quarter............................................... $ 40.44 $ 29.94 +Second quarter.............................................. 36.28 17.87 +Third quarter............................................... 18.68 11.69 +Fourth quarter.............................................. 24.48 12.16 +2000: +First quarter............................................... $ 31.75 $ 12.38 +Second quarter.............................................. 31.81 16.13 +Third quarter............................................... 35.94 18.75 +Fourth quarter.............................................. 38.19 23.06 +As of March 1, 2002, there were approximately 330 holders of record +(approximately 23,400 beneficial holders) of our common shares. +We have not declared or paid cash dividends on our common shares in the +past and do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. Instead, we intend to retain our earnings to support +the operations and growth of our business. Any future cash dividends would +depend on future earnings, capital requirements, financial condition and other +factors deemed relevant by the board of directors. In addition, the terms of our +existing credit facility limit the payment of dividends without the prior +written consent of the lenders. +During 2001, we issued a total of 1,260,070 common shares and three-year +warrants to acquire 325,000 common shares that were not registered under the +Securities Act of 1933, as amended. The shares and warrants were issued as +follows: +- We issued a total of 810,070 common shares during January 2001 as partial +consideration for the acquisition of Jones Drilling Corporation and the +assets of three related entities. +- The remaining 450,000 common shares and warrants to acquire 325,000 +shares were issued during December 2001, as partial consideration for the +acquisition of certain assets of Cleere Drilling Company. +No underwriter was involved in either of the transactions and no sales +commissions, fees or similar compensation were paid by us to any person in +connection with the issuance of the shares. We believe that the issuance of the +shares in each instance was exempt from the registration requirements of Section +5 of the Securities Act by virtue of Section 4(2) of the Securities Act and/or +under Rule 506 of Regulation D promulgated by the SEC thereunder. +17 +ITEM 6. SELECTED FINANCIAL DATA. +The selected consolidated financial data of Patterson-UTI as of December +31, 2001, 2000, 1999, 1998 and 1997 and for each of the five years then ended +should be read in conjunction with "Management's Discussion and Analysis of +Financial Condition and Results of Operations" and the Consolidated Financial +Statements and related Notes thereto, included as Items 7 and 8, respectively, +of this document. Historical financial statements as presented herein, have been +restated to provide for the retroactive effect of the merger with UTI Energy +Corp., on May 8, 2001. +YEAR ENDED DECEMBER 31, +-------------------------------------------------------------- +2001 2000 1999 1998 1997 +---- ---- ---- ---- ---- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +INCOME STATEMENT DATA: +Operating revenues: +Drilling......................... $ 839,931 $ 512,998 $ 266,212 $ 329,003 $ 340,114 +Drilling and completion fluids... 94,456 32,053 11,686 13,397 -- +Pressure pumping................. 39,600 21,465 20,721 23,365 20,923 +Other............................ 15,988 15,806 8,747 7,362 12,694 +---------- ---------- ---------- ---------- ---------- +Total.................... 989,975 582,322 307,366 373,127 373,731 +---------- ---------- ---------- ---------- ---------- +Operating costs and expenses: +Drilling......................... 487,343 384,840 224,590 253,768 253,665 +Drilling and completion fluids... 80,034 26,545 9,864 10,205 -- +Pressure pumping................. 21,146 13,403 12,219 14,041 12,615 +Depreciation, depletion and +amortization.................. 86,159 61,464 52,553 51,436 28,927 +General and administrative....... 28,561 22,190 17,735 20,004 16,675 +Bad debt expense................. 2,045 570 282 1,233 745 +Merger costs..................... 5,943 -- -- -- -- +Restructuring and related +charges....................... 7,202 -- -- -- -- +Other............................ 4,370 4,725 (427) 3,361 2,233 +---------- ---------- ---------- ---------- ---------- +Total.................... 722,803 513,737 316,816 354,048 314,860 +---------- ---------- ---------- ---------- ---------- +Operating income (loss)............ 267,172 68,585 (9,450) 19,079 58,871 +---------- ---------- ---------- ---------- ---------- +Other income (expense)............. (677) (8,481) (7,053) (5,953) (3,581) +---------- ---------- ---------- ---------- ---------- +Income (loss) before income +taxes............................ 266,495 60,104 (16,503) 13,126 55,290 +Income tax expense (benefit)....... 102,333 22,878 (4,766) 5,328 20,475 +---------- ---------- ---------- ---------- ---------- +Net income (loss).................. $ 164,162 $ 37,226 $ (11,737) $ 7,798 $ 34,815 +========== ========== ========== ========== ========== +Net income (loss) per common share: +Basic............................ $ 2.15 $ 0.52 $ (0.18) $ 0.12 $ 0.84 +========== ========== ========== ========== ========== +Diluted.......................... $ 2.07 $ 0.50 $ (0.18) $ 0.12 $ 0.78 +========== ========== ========== ========== ========== +Weighted average number of common +shares outstanding: +Basic............................ 76,407 71,207 66,483 63,785 41,575 +========== ========== ========== ========== ========== +Diluted.......................... 79,197 74,841 66,483 65,757 44,574 +========== ========== ========== ========== ========== +BALANCE SHEET DATA: +Total assets....................... $ 869,642 $ 739,898 $ 496,715 $ 468,554 $ 411,248 +Long-term debt..................... -- 79,416 82,196 87,435 46,758 +Stockholders' equity............... 687,142 481,299 309,695 300,881 290,880 +Working capital.................... 110,172 127,299 45,161 47,837 111,216 +18 +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. These statements include, without limitation, statements relating to: +- liquidity, +- financing of operations, +- continued volatility of oil and natural gas prices, +- source and sufficiency of funds required for capital needs and additional +rig acquisitions (if further opportunities arise), +- future utilization of net operating loss carryforwards, +- impact of inflation on our financial position and on our earnings per +share, and +- other such matters. +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. Readers are +cautioned that such forward-looking statements should be read in conjunction +with our disclosures under the heading: "Cautionary Statement for Purposes of +the 'Safe Harbor' Provisions of the Private Securities Litigation Reform Act of +1995" beginning on page 13. +Off balance sheet arrangements. We have no off balance sheet arrangements +other than letters of credit of $20.0 million at December 31, 2001, maintained +for the benefit of various insurance companies as collateral for retrospective +premiums and retained losses which would become payable under the terms of the +underlying insurance contracts. These letters of credit expire variously during +each calendar year, but provide for an indefinite number of annual extensions of +the expiration date. No amounts have been drawn under the letters of credit. +Trading and investing. We do not engage in trading activities that include +high-risk securities, such as derivatives and non-exchange traded contracts. We +invest cash on hand only in highly liquid, short-term investments such as +overnight deposits, money markets and highly rated municipal and commercial +bonds. +Description of business. We are a leading provider of land-based contract +drilling services to major and independent oil and natural gas producers and +operators in Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Utah and +Western Canada. We own the second largest land-based drilling fleet in North +America with 319 drilling rigs. We provide drilling fluids, completion fluids +and related services to oil and natural gas producers in the Permian Basin of +West Texas and Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf +Coast regions of Texas and Louisiana, and the Gulf of Mexico. Drilling and +completion fluids are used by oil and natural gas operators during the drilling +process to control pressure when drilling oil and natural gas wells. We also +provide pressure pumping services in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for completion of new wells +and remedial work on existing wells. To a lesser extent, we are engaged in the +development, exploration, acquisition and production of oil and natural gas. Our +oil and natural gas operations are not financially material and do not warrant +disclosure as a business segment. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 due to higher oil and natural gas +prices. The increase in demand returned, beginning in mid-1999 and continued +through the second quarter of 2001. However, except for those periods and other +occasional upturns, the market for onshore contract drilling services and the +other services we provide has generally been depressed since 1982, when the +number of operable land drilling rigs was at record levels. Since this time +there have been substantially more drilling rigs available than necessary to +meet demand in most operational and +19 +geographic segments of the North American land drilling industry. As a result, +drilling contractors have had difficulty sustaining profit margins. +In addition to adverse effects that future declines in demand could have on +Patterson-UTI, ongoing factors which could adversely affect utilization rates +and pricing, even in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +- movement of drilling rigs from region to region, +- reactivation of land-based drilling rigs, or +- new construction of drilling rigs. +We cannot predict either the future level of demand for our contract +drilling services or future conditions in the oil and natural gas contract +drilling business. +Management estimates. The preparation of financial statements in +conformity with generally accepted accounting principles requires management to +make estimates and assumptions that affect the reported amounts of assets and +liabilities and disclosure of contingent assets and liabilities at the date of +the financial statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those estimates. +Revenue recognition. Generally, revenues are recognized when services are +performed. We follow the percentage-of-completion method of accounting for +footage contract drilling arrangements. Under this method, all drilling +revenues, direct costs and appropriate portions of indirect costs, related to +the contracts in progress, are recognized as contract drilling services are +performed. Due to the nature of turnkey contract drilling arrangements and risks +therein, we follow the completed contract method of accounting for such +arrangements. Under this method, all drilling advances, direct costs and +appropriate portions of indirect costs (including maintenance and repairs) +related to the contracts in progress are deferred and recognized as revenues and +expenses in the period the contracts are completed. Provisions for losses on +incomplete or in-process contracts are made when estimated total costs are +expected to exceed total estimated revenues. +Related party transactions. In 2001, 2000 and 1999, we leased a 1981 Beech +King-Air 90 airplane owned by an affiliate of our Chief Executive Officer and +our President/Chief Operating Officer. Under the terms of the lease, we paid a +monthly rental of $9,200 and our proportionate share of the costs of fuel, +insurance, taxes and maintenance of the aircraft. We paid approximately +$212,283, $193,769 and $222,583 for the lease of the airplane during 2001, 2000 +and 1999, respectively. +An affiliate acted as the first purchaser of oil produced from certain +leases we operated during 1999. Sales of oil to that entity, both royalty and +working interest were approximately $8.4 million. There were no sales of oil to +that entity in 2001 or 2000. +The Company operates certain oil and natural gas properties in which our +Chief Executive Officer, our President/Chief Operating Officer, our Chief +Financial Officer and other affiliated persons or entities, purchased a joint +interest ownership with us and other industry partners. We made oil and natural +gas production payments (net of royalty) of $8.3 million, $13.4 million and $6.1 +million from these properties in 2001, 2000 and 1999, respectively, to the +aforementioned persons or entities. These persons or entities reimbursed us for +joint operating costs of $5.9 million, $8.0 million and $5.9 million in 2001, +2000 and 1999, respectively. +In 2001, we paid approximately $387,000 to an entity owned by a relative of +our President/Chief Operating Officer for certain equipment and metal +fabrication services. One of our directors is a director and an officer of a +company from which we purchased drill pipe, materials and supplies totalling +approximately $22.0 million in 2001. This same director was an officer of a +customer through February 2001 from which we received approximately $500,000 in +revenues in 2001. +20 +LIQUIDITY AND CAPITAL RESOURCES +As of December 31, 2001, we had working capital of approximately $110.2 +million including cash and cash equivalents of approximately $33.6 million. For +2001, our significant sources of cash flow were: +- $254.0 million derived from operations, +- $6.1 million from the exercise of stock options and warrants, +- $9.8 million of proceeds provided by a credit facility, and +- $742,000 from the sale of certain property and equipment. +Correspondingly, we used a portion of the funds discussed above as follows: +- $89.2 million to repay notes payable, +- $40.5 million as partial consideration in the acquisitions of Jones +Drilling Corporation and the assets of three related entities, the +drilling rigs and certain other assets of Cleere Drilling Company and six +additional drilling rigs from three separate transactions, +- $172.8 million to make capital expenditures for the betterment and +refurbishment of our drilling rigs, as well as the acquisition and +procurement of drilling equipment, including drill pipe, to fund +leasehold acquisition, exploration and development of oil and natural gas +properties and to fund capital expenditures for our drilling and +completion fluids and pressure pumping segments and +- $1.1 million for the purchase of other long-term assets. +During 2001, we entered into five separate transactions, all accounted for +as purchases, whereby we increased our land-based drilling rig fleet to 319, an +increase of 44 rigs from a year ago. A brief description of each of the +transactions follows: +- On December 21, 2001, we acquired 17 drilling rigs and related equipment +from Cleere Drilling Company for an aggregate purchase price of $25.8 +million. The purchase price consisted of $13.5 million cash plus 450,000 +shares of our common stock and warrants to acquire an additional 325,000 +shares of common stock at an exercise price of $26.75 per share. The +common stock was recorded at $21.55 per share and the warrants were +valued at $8.00 per underlying share of our common stock using the +Black-Scholes option valuation model. +- On January 5, 2001, we acquired Jones Drilling Corporation and certain +assets of three entities related to Jones Drilling Corporation. The +acquired assets consisted of 21 drilling rigs (of which 14 were then +marketable) and related equipment and approximately $2.3 million of net +working capital. The purchase price of $33.0 million consisted of 810,070 +shares of the Company's common stock valued at $26.8125 per share and +$11.3 million cash plus approximately $240,000 in transaction costs. +- In January 2001, we acquired six drilling rigs, through three separate +transactions, for approximately $15.7 million cash. +On February 4, 2001, Patterson entered into an Agreement and Plan of Merger +with UTI providing for the merger of the two entities. On May 8, 2001, the +stockholders of each company approved the merger, and the merger was +consummated. Each outstanding share of UTI common stock was converted into one +share of Patterson common stock and each option or warrant then outstanding +representing the right to receive UTI common stock was converted into the right +to purchase Patterson-UTI common stock on an equivalent basis. A total of +37,782,135 shares of Patterson common stock was issued pursuant to the merger +and an additional 3,621,079 shares were reserved for issuance under the UTI +stock option plans. Additionally, our stockholders approved an increase in the +authorized shares of our common stock from 50 million to 200 million and a name +change to "Patterson-UTI Energy, Inc." +During 2001, we repaid $89.2 million under our existing credit facilities +and other term obligations. We incurred expenses of $448,000 as a result of +prepayment penalties and $942,000 related to deferred financing +21 +costs which were unamortized at the time the debt was extinguished. The +penalties and deferred financing costs were included in restructuring and +related charges during 2001. +In June 2001, we increased our existing revolving line of credit to $100.0 +million and extended the term of the facility to June 2005. The revolving line +of credit carries a floating interest rate of LIBOR plus 1.75% to 2.75% based on +twelve-month trailing EBITDA. The facility has no financial covenants unless +availability under the facility is less than $20.0 million. The terms of our +credit facility limit the payment of dividends without the prior written consent +of the lenders. +We believe that the current level of cash and short-term investments, +together with cash generated from operations should be sufficient to meet our +immediate capital needs. From time to time, acquisition opportunities are +reviewed relating to our business. The timing, size or success of any +acquisition and the associated capital commitments are unpredictable. Should +further opportunities for growth requiring capital arise, we believe we would be +able to satisfy these needs through a combination of working capital, cash +generated from operations, and either debt or equity financing. However, there +can be no assurance that such capital would be available. +RESULTS OF OPERATIONS +COMPARISON OF THE YEARS ENDED DECEMBER 31, 2001 AND 2000 +The following tables summarize our operations for the twelve months ended +December 31, 2001 and 2000: +YEAR ENDED DECEMBER 31, +------------------------------------ +CONTRACT DRILLING 2001 2000 % CHANGE +----------------- ---------- ------------ -------- +(DOLLARS IN 000'S) +Revenues.......................................... $ 839,931 $ 512,998 63.7% +Drilling cost..................................... 487,343 384,840 26.6% +Selling, general and administrative............... 5,277 5,457 (3.3)% +Depreciation and amortization..................... 72,797 54,274 34.1% +Operating income.................................. 274,514 68,427 301.2% +Rig utilization rate.............................. 70% 66% 6.1% +Average number of rigs owned...................... 302 263 14.8% +Operating days.................................... 76,871 63,303 21.4% +Average revenue per operating day................. $ 10.93 $ 8.10 34.9% +Average drilling cost per operating day........... 6.34 6.08 4.3% +The significant increases shown were reflective of increased activity in +the contract drilling industry and specifically: +- increases in average rig utilization and in the number of operating days, +- increases in dayrates as evidenced by average revenue per operating day, +and +- the addition of an average 39 drilling rigs from 2000 to 2001. +22 +Largely due to favorable commodity prices during the first half of 2001, +the demand for our contract drilling services was strong as we reached our peak +rig utilization of 81% in July. However, beginning in the third quarter of 2001 +the industry conditions began to deteriorate as the commodity prices of oil and +natural gas significantly weakened. Market prices for oil fell from +approximately $27 per barrel at the end of 2000 to approximately $17 per barrel +in late 2001 and natural gas prices declined from approximately $10 per Mcf to +under $3 per Mcf for the same time period. Accordingly, the demand for our +contract drilling services has been negatively impacted. Should commodity prices +improve, we would expect to begin to see increases in demand. +YEAR ENDED DECEMBER 31, +-------------------------------- +DRILLING AND COMPLETION FLUIDS 2001 2000 % CHANGE +------------------------------ --------- --------- -------- +(DOLLARS IN 000'S) +Revenues............................................ $ 94,456 $ 32,053 194.7% +Drilling and completion fluids cost................. 80,034 26,545 201.5% +Selling, general and administrative................. 7,936 4,294 84.8% +Depreciation and amortization....................... 2,644 1,464 80.6% +Operating income (loss)............................. 3,842 (250) 1,636.8% +Total jobs.......................................... 1,920 601 219.5% +Average revenue per job............................. $ 49.20 $ 53.33 (7.7)% +The increases above were primarily attributable to the purchase of the +fluids division of Ambar, Inc., during October 2000 providing for twelve months +of activity in 2001 versus three months in 2000. Deteriorating industry +conditions as noted above also had an adverse impact on our drilling and +completion fluids division beginning in the third quarter of 2001. Should +industry conditions improve, we would expect to begin to see improvements in +such operations. +YEAR ENDED DECEMBER 31, +-------------------------------- +PRESSURE PUMPING 2001 2000 % CHANGE +---------------- --------- --------- -------- +(DOLLARS IN 000'S) +Revenues............................................ $ 39,600 $ 21,465 84.5% +Pressure pumping cost............................... 21,146 13,403 57.8% +Selling, general and administrative................. 3,910 3,196 22.3% +Depreciation........................................ 1,895 1,564 21.2% +Operating income.................................... 12,649 3,302 283.1% +Total jobs.......................................... 4,609 3,329 38.5% +Average revenue per job............................. $ 8.59 $ 6.45 33.2% +The improvement in the pressure pumping segment's operating results were +primarily attributable to improved market conditions throughout 2001 as +evidenced by the increase in number of jobs and revenue per job. +YEAR ENDED DECEMBER 31, +-------------------------------- +OTHER AND CORPORATE 2001 2000 % CHANGE +------------------- --------- --------- -------- +(DOLLARS IN 000'S) +Revenues............................................ $ 15,988 $ 15,806 1.2% +Other expenses...................................... 4,370 4,725 (7.5)% +Selling, general and administrative................. 11,438 9,243 23.7% +Depreciation, depletion, and amortization........... 8,823 4,162 112.0% +Bad debt expense.................................... 2,045 570 258.8% +Merger costs........................................ 5,943 -- 100.0% +Restructuring and related charges................... 7,202 -- 100.0% +Operating loss...................................... (23,833) (2,894) (723.5)% +The merger costs and restructuring charges incurred in 2001 are associated +with our merger with UTI that occurred in 2001. Weakened commodity prices +resulted in depletion expense increasing from $3.4 million +23 +in 2000 to $7.2 million in 2001. Included in depletion expense in 2001 is +approximately $1.1 million of impairment expense to our oil and natural gas +properties and other valuation allowances associated with impairment to our +undeveloped properties. This impairment is attributable to declining commodity +prices and unfavorable results from certain oil and natural gas prospects. +Selling, general and administrative expenses increased primarily as a result of +the increased activity as evidenced by the operating segments' individual +results of operations and the growth of our Company in 2001 through +acquisitions. Included in this increase are management and operational bonuses +resulting from improved operations. +COMPARISON OF THE YEARS ENDED DECEMBER 31, 2000 AND 1999 +The following tables summarize our operations for the twelve months ended +December 31, 2000 and 1999: +YEAR ENDED DECEMBER 31, +---------------------------------- +CONTRACT DRILLING 2000 1999 % CHANGE +----------------- ---------- ---------- -------- +(DOLLARS IN 000'S) +Revenues.......................................... $ 512,998 $ 266,212 92.7% +Drilling cost..................................... 384,840 224,590 71.4% +Selling, general and administrative............... 5,457 5,142 6.1% +Depreciation and amortization..................... 54,274 46,907 15.7% +Operating income (loss)........................... 68,427 (10,427) 756.2% +Rig utilization rate.............................. 66% 43% 53.5% +Average number of rigs owned...................... 263 231 13.9% +Operating days.................................... 63,303 36,385 74.0% +Average revenue per operating day................. $ 8.10 $ 7.32 10.7% +Average drilling cost per operating day........... 6.08 6.17 (1.5)% +The significant increases shown were reflective of increased activity in +the contract drilling industry and specifically: +- increases in average rig utilization and in the number of operating days, +- increases in dayrates as evidenced by average revenue per operating day, +and +- the addition of an average 32 drilling rigs from 1999 to 2000. +YEAR ENDED DECEMBER 31, +-------------------------------- +DRILLING AND COMPLETION FLUIDS 2000 1999 % CHANGE +------------------------------ --------- --------- -------- +(DOLLARS IN 000'S) +Revenues............................................ $ 32,053 $ 11,686 174.3% +Drilling and completion fluids cost................. 26,545 9,864 169.1% +Selling, general and administrative................. 4,294 2,036 110.9% +Depreciation and amortization....................... 1,464 1,065 37.5% +Operating income (loss)............................. (250) (1,279) 80.5% +Total jobs.......................................... 601 504 19.2% +Average revenue per job............................. $ 53.33 $ 23.19 130.0% +24 +The increases above were primarily attributable to the purchase of the +fluids division of Ambar, Inc., during October 2000 providing for three months +of activity in 2000 and favorable industry conditions during most of 2000. +YEAR ENDED DECEMBER 31, +-------------------------------- +PRESSURE PUMPING 2000 1999 % CHANGE +---------------- --------- --------- -------- +(DOLLARS IN 000'S) +Revenues............................................ $ 21,465 $ 20,721 3.6% +Pressure pumping cost............................... 13,403 12,219 9.7% +Selling, general and administrative................. 3,196 3,457 (7.5)% +Depreciation........................................ 1,564 1,391 12.4% +Operating income.................................... 3,302 3,654 (9.6)% +Total jobs.......................................... 3,329 2,892 15.1% +Average revenue per job............................. $ 6.45 $ 7.16 (9.9)% +YEAR ENDED DECEMBER 31, +------------------------------- +OTHER AND CORPORATE 2000 1999 % CHANGE +------------------- --------- -------- -------- +(DOLLARS IN 000'S) +Revenues............................................. $ 15,806 $ 8,747 80.7% +Other (income) expenses.............................. 4,725 (427) 1,206.6% +Selling, general and administrative.................. 9,243 7,100 30.2% +Depreciation, depletion and amortization............. 4,162 3,190 30.5% +Bad debt expense..................................... 570 282 102.1% +Operating loss....................................... (2,894) (1,398) (107.0)% +The increase in revenues in Other and Corporate is reflective of increased +activity in our oil and natural gas operations resulting from a rise in the +average price received for crude oil from $17.88 per BBL to $30.09 per BBL and a +rise in the average price received for natural gas from $2.31 per Mcf to $4.32 +per Mcf from 1999 to 2000, respectively. +INCOME TAXES +YEAR ENDED DECEMBER 31, +---------------------------------- +2001 2000 1999 +---------- --------- --------- +(DOLLARS IN 000'S) +Total income tax provision (benefit)............. $ 102,333 $ 22,878 $ (4,766) +Effective tax rate............................... 38.4% 38.1% (28.9)% +We recognized income tax benefit of $4.8 million for 1999, resulting from +losses from operations. We recognized income tax expense of $22.9 million for +2000, even though a minimal current expense existed due to loss carryforwards +from prior years. +Our remaining unutilized investment tax credit carryforward expired in +2000. Net operating losses were fully utilized in 2001 and the remaining +alternative minimum tax credit may be carried forward indefinitely. Deferred tax +assets at December 31, 2001, consist primarily of various allowance accounts and +tax deferred expenses expected to generate a future tax benefit of approximately +$8.1 million. +We record non-cash federal deferred income taxes based primarily on the +relationship between the amount of our unused federal NOL carryforwards and the +temporary differences between the book basis and tax basis in our assets. +Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. As a result of fully +recognizing the benefit of our deferred income taxes, we will incur deferred +income tax expense as these benefits are utilized. We incurred deferred income +tax expense of approximately $14.6 million and $15.9 million for 2001 and 2000, +respectively, and a deferred income tax benefit of approximately $4.9 million +for 1999. +25 +VOLATILITY OF OIL AND NATURAL GAS PRICES +Our revenue, profitability and future rate of growth are substantially +dependent upon prevailing prices for oil and natural gas, with respect to all of +our operating segments. Historically, oil and natural gas prices and markets +have been volatile. Prices are affected by market supply and demand factors as +well as actions of state and local agencies, the United States and foreign +governments and international cartels. All of these are beyond our control. Any +significant or extended decline in oil and/or natural gas prices would have a +material adverse effect on our financial condition and results of operations. +Due to a decline in oil and natural gas prices beginning in the second +quarter of 2001, demand for drilling rigs declined beginning in the third +quarter of 2001 and is continuing. This decline in demand has resulted in a +steep decline in drilling rig utilization and day rates, which in turn has +adversely impacted our operations. +IMPACT OF INFLATION +We believe that inflation will not have a significant near-term impact on +our financial position. +RECENTLY-ISSUED ACCOUNTING STANDARDS +The Financial Accounting Standards Board ("FASB") issued Statement of +Financial Accounting Standards No. 141, "Business Combinations," ("SFAS No. +141") in June 2001. SFAS No. 141 addresses financial accounting and reporting +for business combinations and supersedes APB Opinion No. 16, "Business +Combinations," and FASB Statement No. 38, "Accounting for Preacquisition +Contingencies of Purchased Enterprises." SFAS No. 141 is effective for all +business combinations initiated after June 30, 2001 and mandates that such +combinations are to be accounted for using the purchase method. The Company +adopted SFAS No. 141 as of June 30, 2001. +The FASB issued Statement of Financial Accounting Standards No. 142, +"Goodwill and Other Intangible Assets," ("SFAS No. 142") in June 2001. SFAS No. +142 addresses financial accounting and reporting for acquired goodwill and other +intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." SFAS +No. 142 applies to all fiscal years beginning after December 15, 2001. The +provisions of SFAS No. 142, which the Company adopted on January 1, 2002, are +not expected to have a material impact on the Company's consolidated financial +statements. Approximately $4.6 million in amortization expenses recognized +during 2001 would not have been recognized under SFAS No. 142. +The FASB issued Statement of Financial Accounting Standards No. 143, +"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001. +SFAS No. 143 addresses financial accounting requirements for retirement +obligations associated with tangible long-lived assets. SFAS No. 143 is +effective beginning June 15, 2002. The provisions of SFAS No. 143 are not +expected to have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 144, +"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No. +144") in August 2001. SFAS No. 144 addresses financial accounting and reporting +for the impairment or disposal of long-lived assets and supersedes SFAS No. 121 +and APB Opinion No. 30. SFAS No. 144 is effective beginning January 1, 2002, and +is not expected to have a material impact on the Company's consolidated +financial statements. +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 some exposure associated with the floating rate of the +interest charged on that balance. The credit facility, which expires on June 29, +2005, bears interest at LIBOR plus 1.75% to 2.75% based on the Company's +twelve-month trailing EBITDA. Our exposure to interest rate risk due to changes +in LIBOR is not expected to be material. +We conduct some business in Canadian dollars through our Canadian +land-based drilling operations. The exchange rate between Canadian dollars and +U.S. dollars has fluctuated over the last ten years. If the value of +26 +the Canadian dollar against the U.S. dollar weakens, revenues and earnings of +our Canadian operations will be reduced when they are translated to U.S. +dollars. Also, the value of our Canadian net assets in U.S. dollars may decline. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +Financial Statements are filed as a part of this report at the end of Part +IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and +are incorporated herein by this reference. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE. +None. +27 +PART III +The information required by Part III is omitted from this report because +Patterson-UTI will file a definitive proxy statement pursuant to Regulation 14A +of the Securities Exchange Act of 1934 no later than 120 days after the end of +the fiscal year covered by this document and certain information included +therein is incorporated herein by reference. +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 11. EXECUTIVE COMPENSATION. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. +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. +28 +PART IV +ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. +(a)(1) Financial Statements. +See Index to Consolidated Financial Statements on page F-1 of this report. +(a)(2) Financial Statement Schedule. +Schedule II -- Valuation and qualifying accounts is filed herewith on page +S-1. +All other financial statement schedules have been omitted because they are +not applicable or the information required therein is included elsewhere in the +financial statements or notes thereto. +(a)(3) Exhibits. +The following exhibits are filed herewith or incorporated by reference +herein. +2.1 Plan and Agreement of Merger dated October 14, 1993, between +Patterson Energy, Inc., a Texas corporation, and Patterson +Energy, Inc., a Delaware corporation, together with related +Certificates of Merger.(1) +2.2 Agreement and Plan of Merger, dated April 22, 1996 among +Patterson Energy, Inc., Patterson Drilling Company and +Tucker Drilling Company, Inc.(2) +2.2.1 Amendment to Agreement and Plan of Merger, dated May 16, +1996 among Patterson Energy, Inc., Patterson Drilling +Company and Tucker Drilling Company, Inc.(3) +2.3 Agreement and Plan of Merger dated as of January 5, 2001 +among Patterson Energy, Inc., Patterson Drilling Company LP, +LLLP and Jones Drilling Corporation.(4) +2.4 Agreement and Plan of Merger, dated February 4, 2001, by and +between UTI Energy Corp. and Patterson Energy, Inc.(5) +2.5 Asset Purchase Agreement, dated as of December 21, 2001 +among Patterson-UTI Energy, Inc., Patterson-UTI Drilling +Company LP, LLLP and Cleere Drilling Company. +3.1 Restated Certificate of Incorporation.(6) +3.1.1 Certificate of Correction of Restated Certificate of +Incorporation. +3.2 Amended and Restated Bylaws. +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(7) +3.3.1 Amendment to Rights Agreement dated as of October 23, +2001.(15) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson-UTI Energy, Inc. regarding authorized Common Stock +and Preferred Stock.(14) +4.2 Certificate of Designation.(16) +4.2.1 Amendment to Certificate of Designation. +4.3 Registration Rights Agreement with Bear, Stearns and Co. +Inc., dated March 25, 1994, as assigned to REMY Capital +Partners III, L.P. +10.1 Loan and Security Agreement, dated November 22, 1999.(14) +10.1.1 First Amendment to Loan and Security Agreement, dated May 2, +2000.(14) +29 +10.1.2 Second Amendment to Loan and Security Agreement, dated May +18, 2000.(14) +10.1.3 Third Amendment to Loan and Security Agreement, dated +October 18, 2000.(14) +10.1.4 Fourth Amendment to Loan and Security Agreement, dated May +8, 2001.(14) +10.1.5 Fifth Amendment to Loan and Security Agreement, dated June +29, 2001.(14) +10.1.6 Revolving Loan Promissory Note, dated June 29, 2001.(14) +10.1.7 Guaranty Agreement, dated June 29, 2001.(14) +10.1.8 Pledge Agreement, dated June 29, 2001.(14) +10.2 Aircraft Lease, dated December 20, 2000, (effective January +1, 2001) between Talbott Aviation, Inc. and Patterson +Energy, Inc.(8) +10.3 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as +amended.(9) +10.4 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended.(10) +10.5 Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan.(11) +10.6 Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc.(12) +10.7 Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan.(12) +10.8 1997 Stock Option Plan of DSI Industries, Inc.(11) +10.9 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.). +10.10 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Stephen J. DeGroat (a +non-employee director of Patterson-UTI Energy, Inc.). +10.11 Model Form Operating Agreement.(13) +10.12 Form of Drilling Bid Proposal and Footage Drilling +Contract.(13) +10.13 Form of Turnkey Drilling Agreement.(13) +21.1 Subsidiaries of the Registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Auditors -- Ernst & Young LLP. +--------------- +(1) Incorporated herein by reference to Item 27, "Exhibits" to Amendment No. 2 +to Registration Statement on Form SB-2 (File No. 33-68058-FW) filed on +October 28, 1993. +(2) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated April 22, 1996 and filed on April 30, 1996. +(3) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated May 16, 1996 and filed on May 22, 1996. +(4) Incorporated by reference to Item 16, "Exhibits" to Registration Statement +on Form S-3 filed on January 8, 2001. +(5) Incorporated herein by reference to Joint Proxy Statement/Prospectus filed +on March 14, 2001. +(6) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated and filed on May 8, 2001. +30 +(7) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on For 8-A filed on January 14, 1997. +(8) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Form 10-K dated December 31, 2000. +(9) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 333-47917) filed on March 13, 1998. +(10) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on November 4, 1997. +(11) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470) +filed on July 25, 2001. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466) +filed on July 25, 2001. +(13) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993. +(14) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on +August 1, 2001. +(15) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed +on October 31, 2001. +(16) Incorporated herein by reference to Item 2, "Exhibits" to Registration +Statement on Form 8-A (File No. 000-22664) filed on January 14, 1997. +(b) Reports on Form 8-K. +There were no reports on Form 8-K filed during the three months ended +December 31, 2001. +31 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +PAGE +---- +REPORT OF INDEPENDENT ACCOUNTANTS; PRICEWATERHOUSECOOPERS +LLP ...................................................... F-2 +REPORT OF INDEPENDENT ACCOUNTANTS; ERNST & YOUNG LLP........ F-3 +CONSOLIDATED FINANCIAL STATEMENTS: +CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2001 AND +2000................................................... F-4 +CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED +DECEMBER 31, 2001, 2000 AND 1999....................... F-5 +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE +YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999........... F-6 +CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED +DECEMBER 31, 2001, 2000 AND 1999....................... F-7 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS................ F-9 +F-1 +REPORT OF INDEPENDENT ACCOUNTANTS +The Board of Directors and Stockholders of +Patterson-UTI Energy, Inc. +In our opinion, based on our audits and the report of other auditors, the +consolidated financial statements listed in the accompanying index present +fairly, in all material respects, the financial position of Patterson-UTI +Energy, Inc. and its subsidiaries at December 31, 2001 and 2000, and the results +of their operations and their cash flows for each of the three years in the +period ended December 31, 2001 in conformity with accounting principles +generally accepted in the United States of America. In addition, in our opinion, +based on our audits and the report of other auditors, the financial schedule +listed in Item 14(a)(2) presents fairly, in all material respects, the +information set forth therein, when read in conjunction with the related +consolidated financial statements. These financial statements are the +responsibility of the Company's management; our responsibility is to express an +opinion on these financial statements based on our audits. The consolidated +financial statements give retroactive effect to the merger of UTI Energy Corp. +("UTI") on May 8, 2001 in a transaction accounted for as a pooling of interests, +as described in Note 2 to the consolidated financial statements. We did not +audit the financial statements of UTI, which statements reflect total assets of +$330 million as of December 31, 2000 and total revenues of $275 million and $155 +million for the years ended December 31, 2000 and 1999, respectively. Those +statements were audited by other auditors whose report thereon has been +furnished to us, and our opinion expressed herein, insofar as it relates to the +amounts included for UTI, is based solely on the report of the other auditors. +We conducted our audits of these statements in accordance with auditing +standards generally accepted in the United States of America, which require that +we plan and perform the audit to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes +examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements, assessing the accounting principles used and +significant estimates made by management, and evaluating the overall financial +statement presentation. We believe that our audits and the report of other +auditors provide a reasonable basis for our opinion. +PricewaterhouseCoopers LLP +Houston, Texas +January 28, 2002 +F-2 +REPORT OF INDEPENDENT ACCOUNTANTS +To the Board of Directors +Patterson-UTI Energy, Inc. +We have audited the consolidated balance sheet of UTI Energy Corp. as of +December 31, 2000 and the related consolidated statements of operations, changes +in shareholders' equity and cash flows for each of the two years in the period +ended December 31, 2000 (not presented separately herein). Our audits also +included the financial statement schedule listed in the Index at Item 14(a) of +UTI Energy Corp.'s Annual Report (Form 10-K) for the year ended December 31, +2000 (also not presented separately herein). These financial statements and +schedule are the responsibility of the Company's management. Our responsibility +is to express an opinion on these financial statements and schedule based on our +audits. +We conducted our audits in accordance with auditing standards generally +accepted in the United States. Those standards require that we plan and perform +the audit to obtain reasonable assurance about whether the financial statements +are free of material misstatement. An audit also includes assessing the +accounting principles used and significant estimates made by management, as well +as evaluating the overall financial statement presentation. We believe that our +audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above +present fairly, in all material respects, the consolidated financial position of +UTI Energy Corp. at December 31, 2000, and the consolidated results of its +operations and its cash flows for each of the two years in the period ended +December 31, 2000, in conformity with accounting principles generally accepted +in the United States. Also, in our opinion, the related financial statement +schedule, when considered in relation to the basic financial statements taken as +a whole, presents fairly in all material respects the information set forth +therein. +Ernst & Young LLP +Houston, Texas +February 16, 2001 +F-3 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +DECEMBER 31, +----------------------- +2001 2000 +---------- ---------- +ASSETS +Current assets: +Cash and cash equivalents................................. $ 33,584 $ 66,916 +Accounts receivable, net of allowance for doubtful +accounts of $4,021 and $3,462 at December 31, 2001 and +2000, respectively..................................... 133,837 136,894 +Federal and state income taxes receivable, net............ 1,673 2,447 +Inventory................................................. 16,272 12,953 +Deferred tax assets....................................... 8,747 11,090 +Other..................................................... 5,345 7,442 +---------- ---------- +Total current assets.............................. 199,458 237,742 +Property and equipment, at cost, net........................ 614,420 442,559 +Intangible assets, net...................................... 51,634 56,373 +Other....................................................... 4,130 3,224 +---------- ---------- +Total assets...................................... $ 869,642 $ 739,898 +========== ========== +LIABILITIES AND STOCKHOLDERS' EQUITY +Current liabilities: +Current maturities of notes payable....................... $ -- $ 4,477 +Accounts payable: +Trade.................................................. 47,945 71,769 +Other.................................................. 4,833 10,119 +Accrued expenses.......................................... 36,508 24,078 +---------- ---------- +Total current liabilities......................... 89,286 110,443 +Deferred tax liabilities.................................... 92,859 71,899 +Other....................................................... 355 1,318 +Notes payable............................................... -- 74,939 +---------- ---------- +Total liabilities................................. 182,500 258,599 +---------- ---------- +Commitments and contingencies............................... -- -- +Stockholders' equity: +Preferred stock, par value $.01; authorized 1,000 shares, +no shares issued....................................... -- -- +Common stock, par value $.01; authorized 200,000 shares with +78,463 and 76,250 issued and 76,956 and 74,743 outstanding +at December 31, 2001 and 2000, respectively............... 784 763 +Additional paid-in capital.................................. 441,475 397,489 +Retained earnings........................................... 258,834 94,672 +Accumulated other comprehensive income (loss)............... (2,296) 30 +Treasury stock, at cost, 1,507 shares....................... (11,655) (11,655) +---------- ---------- +Total stockholders' equity........................ 687,142 481,299 +---------- ---------- +Total liabilities and stockholders' equity........ $ 869,642 $ 739,898 +========== ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-4 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +YEARS ENDED DECEMBER 31, +------------------------------------ +2001 2000 1999 +---------- ---------- ---------- +Operating revenues: +Drilling............................................. $ 839,931 $ 512,998 $ 266,212 +Drilling and completion fluids....................... 94,456 32,053 11,686 +Pressure pumping..................................... 39,600 21,465 20,721 +Other................................................ 15,988 15,806 8,747 +---------- ---------- ---------- +989,975 582,322 307,366 +---------- ---------- ---------- +Operating costs and expenses: +Drilling............................................. 487,343 384,840 224,590 +Drilling and completion fluids....................... 80,034 26,545 9,864 +Pressure pumping..................................... 21,146 13,403 12,219 +Depreciation, depletion and amortization............. 86,159 61,464 52,553 +General and administrative........................... 28,561 22,190 17,735 +Bad debt expense..................................... 2,045 570 282 +Merger costs......................................... 5,943 -- -- +Restructuring and related charges.................... 7,202 -- -- +Other................................................ 4,370 4,725 (427) +---------- ---------- ---------- +722,803 513,737 316,816 +---------- ---------- ---------- +Operating income (loss)................................ 267,172 68,585 (9,450) +---------- ---------- ---------- +Other income (expense): +Interest income...................................... 2,080 1,377 1,047 +Interest expense..................................... (3,142) (10,108) (8,269) +Other................................................ 385 250 169 +---------- ---------- ---------- +(677) (8,481) (7,053) +---------- ---------- ---------- +Income (loss) before income taxes...................... 266,495 60,104 (16,503) +---------- ---------- ---------- +Income tax expense (benefit): +Current.............................................. 87,773 6,931 134 +Deferred............................................. 14,560 15,947 (4,900) +---------- ---------- ---------- +102,333 22,878 (4,766) +---------- ---------- ---------- +Net income (loss)...................................... $ 164,162 $ 37,226 $ (11,737) +========== ========== ========== +Net income (loss) per common share: +Basic................................................ $ 2.15 $ 0.52 $ (0.18) +========== ========== ========== +Diluted.............................................. $ 2.07 $ 0.50 $ (0.18) +========== ========== ========== +Weighted average number of common shares outstanding: +Basic................................................ 76,407 71,207 66,483 +========== ========== ========== +Diluted.............................................. 79,197 74,841 66,483 +========== ========== ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-5 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +(In thousands) +COMMON STOCK ACCUMULATED +------------------ ADDITIONAL OTHER +NUMBER PAID-IN RETAINED COMPREHENSIVE TREASURY +OF SHARES AMOUNT CAPITAL EARNINGS INCOME (LOSS) STOCK TOTAL +--------- ------ ---------- ---------- ------------- ---------- ---------- +December 31, 1998.......... 64,897 $ 649 $ 241,054 $ 69,183 $ -- $ (10,005) $ 300,881 +Issuance of common +stock................. 3,422 34 17,439 -- -- -- 17,473 +Stock option +compensation.......... -- -- 250 -- -- -- 250 +Exercise of stock +options............... 1,223 12 2,118 -- -- -- 2,130 +Tax benefit related to +exercise of stock +options............... -- -- 698 -- -- -- 698 +Net loss................. -- -- -- (11,737) -- -- (11,737) +-------- ------ ---------- ---------- --------- ---------- ---------- +December 31, 1999.......... 69,542 695 261,559 57,446 -- (10,005) 309,695 +Issuance of common +stock................. 4,203 42 120,964 -- -- -- 121,006 +Issuance of stock +purchase warrant...... -- -- 900 -- -- -- 900 +Treasury stock +acquired.............. -- -- -- -- -- (1,650) (1,650) +Exercise of stock +purchase warrants..... 1,054 11 683 -- -- -- 694 +Exercise of stock +options............... 1,451 15 6,254 -- -- -- 6,269 +Tax benefit related to +exercise of stock +options............... -- -- 7,129 -- -- -- 7,129 +Foreign currency +translation........... -- -- -- -- 30 -- 30 +Net income............... -- -- -- 37,226 -- -- 37,226 +-------- ------ ---------- ---------- --------- ---------- ---------- +December 31, 2000.......... 76,250 763 397,489 94,672 30 (11,655) 481,299 +Issuance of common +stock................. 1,260 12 31,405 -- -- -- 31,417 +Issuance of stock +purchase warrant...... -- -- 2,600 -- -- -- 2,600 +Exercise of stock +purchase warrants..... 121 1 1,819 -- -- -- 1,820 +Exercise of stock +options............... 832 8 4,237 -- -- -- 4,245 +Tax benefit related to +exercise of stock +options............... -- -- 3,925 -- -- -- 3,925 +Foreign currency +translation........... -- -- -- -- (2,326) -- (2,326) +Net income............... -- -- -- 164,162 -- -- 164,162 +-------- ------ ---------- ---------- --------- ---------- ---------- +December 31, 2001.......... 78,463 $ 784 $ 441,475 $ 258,834 $ (2,296) $ (11,655) $ 687,142 +======== ====== ========== ========== ========= ========== ========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-6 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +YEARS ENDED DECEMBER 31, +-------------------------------------- +2001 2000 1999 +----------- ----------- ---------- +Cash flows from operating activities: +Net income (loss).................................. $ 164,162 $ 37,226 $ (11,737) +Adjustments to reconcile net income (loss) to net +cash provided by operating activities: +Depreciation, depletion and amortization........... 86,159 61,464 52,553 +Bad debt expense................................... 2,045 570 282 +Deferred income tax expense (benefit).............. 14,560 15,947 (4,900) +Other.............................................. (647) 881 (2,356) +Changes in operating assets and liabilities: +Trade accounts receivable and other current +assets..................................... 9,612 (54,679) (15,703) +Inventory..................................... (3,320) (1,539) (796) +Accrued federal income taxes receivable....... 4,721 2,596 6,557 +Trade accounts payable and other +liabilities................................ (23,286) 35,731 14,532 +----------- ----------- ---------- +Net cash provided by operating +activities............................... 254,006 98,197 38,432 +----------- ----------- ---------- +Cash flows from investing activities: +Acquisitions....................................... (40,546) (56,627) (7,540) +Purchases of property and equipment................ (172,850) (95,822) (28,529) +Proceeds from sales of property and equipment...... 742 3,528 7,469 +Change in other assets and intangible assets....... (1,101) 630 (1,281) +----------- ----------- ---------- +Net cash used in investing activities...... (213,755) (148,291) (29,881) +----------- ----------- ---------- +Cash flows from financing activities: +Proceeds from issuance of common stock............. -- 98,766 -- +Purchase of treasury stock......................... -- (1,650) -- +Proceeds from issuance of notes payable............ 9,760 76,392 50,000 +Payments of notes payable.......................... (89,176) (79,766) (63,665) +Proceeds from exercise of stock options and +warrants........................................ 6,065 6,963 2,130 +----------- ----------- ---------- +Net cash provided by (used in) financing +activities............................... (73,351) 100,705 (11,535) +----------- ----------- ---------- +Net increase (decrease) in cash and cash +equivalents.............................. (33,100) 50,611 (2,984) +Effect of exchange rate changes on cash.... (232) (34) -- +Cash and cash equivalents at beginning of year....... 66,916 16,339 19,323 +----------- ----------- ---------- +Cash and cash equivalents at end of year............. $ 33,584 $ 66,916 $ 16,339 +=========== =========== ========== +Supplemental disclosure of cash flow information: +Net cash paid during the year for: +Interest................................... $ 3,142 $ 10,097 $ 7,343 +Income taxes............................... 81,802 3,319 1,012 +The accompanying notes are an integral part of these consolidated financial +statements. +F-7 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED) +Non-cash investing and financing activities: +During 2001 the Company acquired Jones Drilling Corporation and certain +assets of three other entities affiliated with Jones Drilling Corporation for +$33.0 million, drilling rigs and related equipment from Cleere Drilling Company +for an aggregate purchase price of $25.8 million and six drilling rigs through +three separate transactions for $15.7 million. Of the $74.6 million, +approximately $40.5 million was paid in cash as follows: +(IN THOUSANDS) +Purchase price.............................................. $ 74,563 +Less non-cash items: +Common stock issued....................................... (31,417) +Warrants issued........................................... (2,600) +---------- +Total cash paid................................... $ 40,546 +========== +During May, 2000, the Company, in a non monetary exchange of similar +productive assets, acquired a drilling rig in exchange for certain drilling rig +components and drill pipe with a net book value of approximately $970,000. No +gain or loss was recognized on this transaction. +During 2000, the Company acquired WEK Drilling Co., Inc., High Valley +Drilling, Inc., the land drilling operations of Phelps Drilling International, +Ltd. and the drilling and completion fluids operations of Ambar, Inc., for an +aggregate purchase price of approximately $70.6 million, of which approximately +$47.4 million was paid in cash as follows: +(IN THOUSANDS) +Purchase price.............................................. $ 70,558 +Less non-cash items: +Common stock issued....................................... (22,240) +Warrants issued........................................... (900) +---------- +Total cash paid................................... $ 47,418 +========== +During 1999, the Company acquired Norton Drilling Services, Inc., Schneider +Drilling Corporation and the drilling assets of Padre Industries, Inc. for an +aggregate purchase price of $32.7 million, of which approximately $7.5 million +was paid in cash. +(IN THOUSANDS) +Purchase price.............................................. $ 32,763 +Less non-cash items: +Common stock issued....................................... (17,312) +Debt assumed.............................................. (7,951) +---------- +Total cash paid................................... $ 7,500 +========== +The accompanying notes are an integral part of these consolidated financial +statements. +F-8 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +A description and basis of presentation follows: +Description of business -- Patterson-UTI Energy, Inc. and 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 producers and operators in Texas, New +Mexico, Oklahoma, Louisiana, Mississippi, Utah and Western Canada. The Company +owns the second largest land-based drilling fleet in North America with 319 +drilling rigs. The Company provides drilling fluids, completion fluids and +related services to oil and natural gas producers in the Permian Basin of West +Texas and Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf +Coast regions of Texas and Louisiana and the Gulf of Mexico. The Company also +provides pressure pumping services in the Appalachian Basin. To a lesser extent, +the Company is engaged in the development, exploration, acquisition and +production of oil and natural gas. The Company's oil and natural gas operations +are not financially material and do not warrant disclosure as a business +segment. +Patterson Energy, Inc. ("Patterson") and UTI Energy Corp. ("UTI") +consummated a merger, with Patterson as the surviving entity, which was treated +as a reorganization within the meaning of Section 368(a) of the Internal Revenue +Code of 1986, as amended, and accounted for as a pooling of interests for +financial accounting purposes. Accordingly, historical financial statements as +presented herein, have been restated to provide for the retroactive effect of +the merger. At the time of the merger, the name of Patterson Energy, Inc. was +changed to "Patterson-UTI Energy, Inc." (See Note 2). +Basis of presentation -- The consolidated financial statements of +Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been prepared +to give retroactive effect to the merger between Patterson and UTI on May 8, +2001. These financial statements also give retroactive effect to the two for one +stock split in October 2001 by UTI. +A summary of the significant accounting policies follows: +Principles of consolidation -- The consolidated financial statements +include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All +significant intercompany accounts and transactions have been eliminated. +Management estimates -- The preparation of financial statements in +conformity with generally accepted accounting principles requires management to +make estimates and assumptions that affect the reported amounts of assets and +liabilities and disclosure of contingent assets and liabilities at the date of +the financial statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those estimates. +Revenue recognition -- Generally, revenues are recognized when services are +performed. The Company follows the percentage-of-completion method of accounting +for footage contract drilling arrangements. Under this method, all drilling +revenues, direct costs and appropriate portions of indirect costs, related to +the contracts in progress, are recognized as contract drilling services are +performed. Due to the nature of turnkey contract drilling arrangements and risks +therein, the Company follows the completed contract method of accounting for +such arrangements. Under this method, all drilling advances, direct costs and +appropriate portions of indirect costs (including maintenance and repairs) +related to the contracts in progress are deferred and recognized as revenues and +expenses in the period the contracts are completed. Provisions for losses on +incomplete or in-process contracts are made when estimated total costs are +expected to exceed total estimated revenues. +Inventories -- Inventories consist primarily of chemical products to be +used in conjunction with the Company's drilling and completion fluids +activities. The inventories are stated at the lower of cost or market, +determined by the first-in, first-out method. +F-9 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING +POLICIES -- (CONTINUED) +Property and equipment -- Property and equipment (other than oil and +natural gas) -- is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated useful lives as +defined below. The Company incurred depreciation expense of approximately $72.6 +million, $52.0 million and $43.9 million for 2001, 2000 and 1999, respectively. +USEFUL +LIVES (YEARS) +------------- +Drilling rigs and related equipment......................... 2-15 +Office furniture............................................ 3-10 +Buildings................................................... 5-30 +Automotive equipment........................................ 2-7 +Other....................................................... 3-7 +Oil and natural gas properties -- The Company follows the successful +efforts method of accounting, using the field as its accumulation center for +capitalized costs. Under the successful efforts method of accounting, costs +which result directly in the discovery of oil and natural gas reserves and all +development costs are capitalized. Exploration costs which do not result +directly in discovering oil and natural gas reserves are charged to expense when +such determinations are made. The capitalized costs, consisting of lease and +well equipment, lease acquisition costs and intangible development costs are +depreciated, depleted and amortized on the units-of-production method, based on +petroleum engineer estimates of recoverable proved developed oil and natural gas +reserves of each respective field. The Company incurred depletion expense of +approximately $7.2 million, $3.4 million and $2.6 million for 2001, 2000 and +1999, respectively. +Impairment of long-lived assets -- Net capitalized costs of long-lived +assets, certain identifiable intangibles and goodwill are reduced to reflect an +amount which is expected to be recovered through the future cash flows generated +by the use of the related assets. Impairment of proved oil and natural gas +properties is periodically assessed based on estimated future net cash flows at +a field level as determined by an independent reserve engineer. The Company +incurred approximately $1.2 million and $275,000 of impairment to such +properties for 2001 and 1999, respectively. Impairment of the oil and natural +gas properties was primarily attributable to declines in the market prices of +crude oil and natural gas and related revisions to existing reserve estimates. +Impairment expense is included in depreciation, depletion and amortization in +the accompanying financial statements. +Maintenance and repairs -- Maintenance and repairs are charged against +operations. Renewals and betterments which extend the life or improve existing +properties are capitalized. +Retirements -- Upon disposition or retirement of property and equipment +(other than oil and natural gas properties), the cost and related accumulated +depreciation are removed and the gain or loss thereon, if any, is credited or +charged to operations. The Company recognizes the gain or loss on the sale of +either a part of a proved oil and natural gas property or an entire proved oil +and natural gas property constituting a part of a field upon the sale or +disposition of such. The unamortized cost of the property or group of +properties, a part of which was sold or otherwise disposed of, is apportioned to +the interest sold and the interest retained on the basis of the fair value of +those interests. +Intangible assets -- Intangible assets consist primarily of goodwill and +covenants not to compete arising from business combinations (see Notes 2 and 5). +The values assigned to intangible assets, based in part upon independent +appraisals, are amortized on a straight line basis. Goodwill, representing the +excess of the purchase price over the estimated fair value of the net assets of +the acquired business, is amortized over the period of expected benefit of 15 +years. Covenants not to compete are amortized over their underlying +F-10 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING +POLICIES -- (CONTINUED) +contractual lives. Amortization expense charged to operations for the years +ended December 31, 2001, 2000 and 1999 was approximately $5.2 million, $6.0 +million and $5.8 million, respectively. +Earnings per share -- The Company provides a dual presentation of its +earnings per share; Basic Earnings per Share ("Basic EPS") and Diluted Earnings +per Share ("Diluted EPS") in its Consolidated Statements of Operations. 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. Dilutive securities, consisting of certain stock options and +warrants as described in Note 10, of approximately 4.1 million were excluded +from the December 31, 1999 calculation of Diluted EPS as a result of the +Company's net loss for that year. For the years ended December 31, 2001 and +2000, dilutive securities included in the calculation of Diluted EPS were 2.8 +million shares and 3.6 million shares, respectively. There are 490,000 of +potentially dilutive shares and warrants outstanding at December 31, 2001 due to +their exercise prices being greater than the average exercise price for the year +2001. +Income taxes -- The asset and liability method is used in accounting for +income taxes. Under this method, deferred tax assets and liabilities are +recognized for operating loss and tax credit carryforwards and for the future +tax consequences attributable to differences between the financial statement +carrying amounts of existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the years in which those temporary +differences are expected to be recovered or settled. The effect on deferred tax +assets and liabilities of a change in tax rates is recognized in the results of +operations in the period that includes the enactment date. 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 -- The Company grants stock options to employees +and non-employee directors under stock-based incentive compensation plans, (the +"Plans"). The Company uses the intrinsic value based method of accounting for +the Plans. Under this method, the Company records no compensation expense for +stock options granted when the exercise price for options granted is equal to or +greater than the fair market value of the Company's stock on the date of the +grant. +Statement of cash flows -- For purposes of reporting cash flows, cash and +cash equivalents include cash on hand, cash on deposit and unrestricted +certificates of deposit with original maturities of 90 days or less. +Recently Issued Accounting Standards -- The Financial Accounting Standards +Board ("FASB") issued Statement of Financial Accounting Standards No. 141, +"Business Combinations," ("SFAS No. 141") in June 2001. SFAS No. 141 addresses +financial accounting and reporting for business combinations and supersedes APB +Opinion No. 16, "Business Combinations," and FASB Statement No. 38, "Accounting +for Preacquisition Contingencies of Purchased Enterprises." SFAS No. 141 is +effective for all business combinations initiated after June 30, 2001 and +mandates that such combinations are to be accounted for using the purchase +method. The Company adopted SFAS No. 141 as of June 30, 2001. +The FASB issued Statement of Financial Accounting Standards No. 142, +"Goodwill and Other Intangible Assets," ("SFAS No. 142") in June 2001. SFAS No. +142 addresses financial accounting and reporting for acquired goodwill and other +intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." SFAS +No. 142 applies to all fiscal years beginning after December 15, 2001. The +provisions of SFAS No. 142, which the Company adopted on January 1, 2002, are +not expected to have a material impact on the Company's consolidated financial +statements. Approximately $4.6 million in amortization expenses recognized +during 2001 would not have been recognized under SFAS No. 142. +F-11 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING +POLICIES -- (CONTINUED) +The FASB issued Statement of Financial Accounting Standards No. 143, +"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001. +SFAS No. 143 addresses financial accounting requirements for retirement +obligations associated with tangible long-lived assets. SFAS No. 143 is +effective beginning June 15, 2002. The provisions of SFAS No. 143 are not +expected to have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 144, +"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No. +144") in August 2001. SFAS No. 144 addresses financial accounting and reporting +for the impairment or disposal of long-lived assets and supersedes SFAS No. 121 +and APB Opinion No. 30. SFAS No. 144 is effective beginning January 1, 2002, and +is not expected to have a material impact on the Company's consolidated +financial statements. +Reclassifications -- Certain reclassifications have been made to the 1999 +and 2000 consolidated financial statements in order for them to conform with the +2001 presentation. +2. MERGERS AND ACQUISITIONS +2001 MERGER AND ACQUISITIONS +Cleere Drilling Company -- On December 21, 2001, the Company acquired 17 +drilling rigs and related equipment from Cleere Drilling Company for an +aggregate purchase price of $25.8 million. The purchase price consisted of $13.5 +million cash plus 450,000 shares of its common stock and warrants to acquire an +additional 325,000 shares of common stock at an exercise price of $26.75 per +share. The common stock was recorded at $21.55 per share and the warrants were +valued at $8.00 per underlying share of the Company's Common Stock using the +Black-Scholes option valuation model. All of the purchase price was allocated to +the rigs acquired. +UTI Energy Corp. -- On February 4, 2001, Patterson entered into an +Agreement and Plan of Merger with UTI providing for the merger of the two +entities. On May 8, 2001, the stockholders of each company approved the merger +and the merger was consummated. Each outstanding share of UTI common stock was +converted into one share of Patterson common stock and each option or warrant +then outstanding representing the right to receive UTI common stock was +converted into the right to purchase Patterson-UTI common stock on an equivalent +basis. A total of 37,782,135 shares of common stock was issued pursuant to the +merger and an additional 3,621,079 shares were reserved for issuance under the +then outstanding UTI stock option plans. Additionally, the stockholders of +Patterson approved an increase in the authorized shares of common stock from 50 +million to 200 million and a name change to "Patterson-UTI Energy, Inc." +The Company incurred $13.1 million in expenses related to the merger, of +which approximately $2.2 million are unpaid as of December 31, 2001. Such +expenses consisted of $5.9 million in merger costs which were primarily related +to professional fees paid to investment banking firms, attorneys, accountants +and commercial printers for their professional services rendered and $7.2 +million in restructuring costs and related charges incurred as a result of the +following: +- severance costs and related expenses of $2.8 million, +- closing of duplicate operational facilities of $1.6 million, +- costs of $1.4 million incurred in connection with changes to the +Company's credit facilities (see Note 7), and +- fees and expenses related to the transfer of licenses and leaseholds, and +in some instances the impairment of such leaseholds, the combination or +cancellation of various service contracts and the renegotiation of +certain insurance policies of approximately $1.4 million. +F-12 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2. MERGERS AND ACQUISITIONS -- (CONTINUED) +The merger was treated as a reorganization within the meaning of Section +368(a) of the Internal Revenue Code of 1986, as amended, and was accounted for +as a pooling of interests for financial accounting purposes. The consolidated +financial statements give retroactive effect to the merger, which includes +combining the companies' historical consolidated financial statements for the +years ended December 31, 2000 and 1999. Certain adjustments were made in those +periods to conform the previous accounting policies of UTI with those of +Patterson. +Selected unaudited pro forma information related to the operations of +Patterson and UTI for the three months ended March 31, 2001 follows (in +thousands): +PATTERSON UTI ADJUSTMENTS COMBINED +--------- -------- ----------- -------- +(UNAUDITED) +Revenues.................................. $129,936 $108,390 $260 $238,586 +Operating income.......................... 32,702 26,431 27 59,160 +Net income................................ 20,544 16,050 17 36,611 +Jones Drilling Corporation -- On January 5, 2001, the Company consummated +the transactions contemplated by certain agreements among the Company and Jones +Drilling Corporation and three of its affiliated entities. The acquired assets +consisted of 21 drilling rigs and related equipment and approximately $2.3 +million of net working capital. The purchase price of $33.2 million consisted of +810,070 shares of the Company's common stock valued at $26.8125 per share and +$11.3 million cash plus approximately $240,000 in transaction costs. The +purchase price, net of working capital was allocated among the assets acquired +based on their estimated fair market values as of the date of the transaction. +Other. In January 2001, the Company acquired six drilling rigs, through +three separate transactions, for approximately $15.7 million cash in aggregate. +All of the purchase price was allocated to the rigs acquired. +2000 MERGER AND ACQUISITIONS +Ambar, Inc. -- In October 2000, the Company completed, through a wholly +owned subsidiary, the acquisition of the drilling and completion fluid +operations of Ambar, Inc., a non-affiliated entity with its principal operations +in Louisiana, the Gulf Coast region of South Texas and the Gulf of Mexico. The +purchase price of $12.4 million consisted of cash of $11.7 million and $680,000 +of direct costs incurred related to the acquisition. The assets acquired +included net working capital of approximately $7.8 million (current assets of +$18.2 million and current liabilities assumed of $10.4 million). The purchase +price, net of working capital acquired, was allocated to the fixed assets based +on their estimated fair market values as of the date of the transaction. +The Company's operating results include the operations of the acquired +entity since the acquisition date. The following summary, prepared on a pro +forma basis, combines the consolidated results of operations as if the +transactions had occurred on January 1, 1999, after including the impact of +certain adjustments, such as +F-13 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2. MERGERS AND ACQUISITIONS -- (CONTINUED) +restatement of depreciation using fair values instead of book values of the +assets acquired, the increased interest expense on the acquisition debt and the +related income tax effects. +YEAR ENDED DECEMBER 31, +------------------------- +2000 1999 +----------- ----------- +(UNAUDITED) +(IN THOUSANDS, EXCEPT PER +SHARE AMOUNTS) +Revenues.................................................... $632,416 $373,674 +Net income (loss)........................................... 38,315 (12,767) +Net income (loss) per basic share........................... $ 0.54 $ (0.19) +Net income (loss) per diluted share......................... 0.51 (0.19) +The pro forma results have been prepared for comparative purposes only and +do not purport to be indicative of what would have occurred had the acquisition +been made as of the date indicated. In addition, they are not intended to be a +projection of future results and do not reflect any synergies that might be +achieved from combined operations. +In September 2000, the Company acquired four drilling rigs in two separate +transactions for a total of $7.7 million in cash. The purchase price was +allocated to the rigs acquired. +High Valley Drilling, Inc. -- On June 2, 2000, the Company completed the +merger of High Valley Drilling, Inc., a privately held, non-affiliated company, +with and into Patterson-UTI Drilling Company LP, LLLP, a wholly owned subsidiary +of Patterson-UTI. The purchase price of $21.8 million was funded using 1,150,000 +shares of common stock valued at $18 per share, three-year warrants to acquire +127,000 shares at $22 per share and approximately $208,000 of direct costs +incurred related to the transaction. Using a Black-Scholes model, the warrants +were valued at $900,000. The assets acquired consisted of eight drilling rigs +and other related equipment. The purchase price was allocated among such assets +based upon the estimated fair market value of the drilling rigs and related +equipment. +Asset Swap. -- On May 15, 2000, the Company, in a non-monetary exchange, +acquired a drilling rig in exchange for certain drilling rig components and +drill pipe with a net book value of approximately $970,000. No gain or loss was +recognized on this transaction. +Phelps Drilling International Ltd. -- On May 5, 2000, the Company acquired +the land drilling operations of Phelps Drilling International Ltd. for $29.6 +million in cash. Phelps' assets and operations are located in the Canadian +provinces of Alberta, Saskatchewan and British Columbia. The acquisition was +accounted for under the purchase method of accounting. The acquired assets +consisted of fourteen land drilling rigs and related equipment. The purchase +price was allocated among such assets based upon the fair market value of the +drilling rigs and related equipment. +WEK Drilling Co., Inc. -- On March 31, 2000, the Company acquired the +outstanding stock of WEK Drilling Co., Inc., a privately held, non-affiliated +drilling company with its principal operations in Southeast New Mexico. The +purchase price of $6.8 million, which is net of cash acquired, was funded using +$5.66 million of proceeds from the Company's existing credit facility and 53,000 +shares of the Company's common stock valued at $29.0625 per share and +approximately $77,000 of direct costs incurred related to the transaction. The +assets acquired consisted of four operable drilling rigs, other related +equipment, and working capital of $1.2 million. Immediately following the +transaction, certain assets unrelated to the oil and natural gas industry were +sold back to one of the previous owners for a cash payment of $1.0 million. The +purchase price of $6.8 million, less the $1.0 million of unrelated assets that +were subsequently sold and the net working capital acquired, was allocated among +the acquired assets based upon the estimated fair market value of the drilling +rigs and related equipment. +F-14 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2. MERGERS AND ACQUISITIONS -- (CONTINUED) +1999 ACQUISITIONS +Schneider Drilling Corporation -- On December 14, 1999, the Company +acquired the land drilling assets of Schneider Drilling Corporation for $7.5 +million in cash. The acquisition was accounted for under the purchase method of +accounting. Schneider's assets included three land drilling rigs, major +components for two additional drilling rigs and drilling equipment. The purchase +price was allocated among such assets based upon the fair market value of the +drilling rigs and related equipment. +Norton Drilling Services, Inc. -- On July 27, 1999, the Company acquired +Norton Drilling Services, Inc., for approximately 2.6 million shares of the +Company's common stock valued at $5.12 per common share, for a purchase price of +$13.3 million. The Company also repaid approximately $8.0 million of Norton's +existing debt upon the acquisition. The acquisition was accounted for under the +purchase method of accounting. Norton's assets included sixteen drilling rigs +and related equipment. The purchase price was allocated among the assets and +liabilities acquired based upon their fair market value. +Padre Industries, Inc. -- On January 27, 1999, the Company completed the +acquisition of five drilling rigs and other related equipment from a privately +held, non-affiliated entity based in Corpus Christi, Texas. The purchase price +consisted of 800,000 shares of the Company's stock at a guaranteed value of +$5.00 per share. As part of the acquisition agreement, the Company had the +option exercisable on February 1, 2000 to buy back 300,000 of the 800,000 shares +at $5.50 per share. The Company exercised its option on February 1, 2000. The +purchase price of $4.0 million was allocated among such assets based upon the +estimated fair market value of the drilling rigs and related equipment. +The aforementioned acquisitions, excluding the merger with UTI, completed +during fiscal years 2001, 2000 and 1999 have been accounted for as purchases and +the related results of operations and cash flows of the acquired entities have +been included in the consolidated financial statements since their respective +dates of acquisition. +3. COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE INCOME +The following table illustrates the Company's comprehensive income +including the effects of foreign currency translation adjustments for the years +ended December 31, 2001 and 2000 (in thousands): +2001 2000 +---------- --------- +Net income.................................................. $ 164,162 $ 37,226 +Other comprehensive income (loss): +Foreign currency translation adjustment related to our +Canadian operations....................................... (2,326) 30 +---------- --------- +Comprehensive income........................................ $ 161,836 $ 37,256 +========== ========= +Accumulated other comprehensive income at December 31, 2001 and 2000 +consists entirely of foreign currency translation adjustments. +F-15 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +4. PROPERTY AND EQUIPMENT +Property and equipment consisted of the following at December 31, 2001 and +2000 (in thousands): +2001 2000 +----------- ----------- +Drilling rigs and related equipment....................... $ 810,910 $ 592,717 +Other equipment........................................... 46,201 30,410 +Oil and natural gas properties............................ 51,080 40,686 +Buildings................................................. 10,357 9,836 +Land...................................................... 3,703 3,273 +----------- ----------- +922,251 676,922 +Less accumulated depreciation and depletion............... (307,831) (234,363) +----------- ----------- +$ 614,420 $ 442,559 +=========== =========== +5. INTANGIBLE ASSETS +Intangible assets consisted of the following at December 31, 2001 and 2000 +(in thousands): +2001 2000 +----------- ----------- +Goodwill.................................................. $ 69,860 $ 69,860 +Covenants not to compete.................................. 2,048 1,861 +Other..................................................... 1,587 1,341 +----------- ----------- +73,495 73,062 +Less accumulated amortization............................. (21,861) (16,689) +----------- ----------- +$ 51,634 $ 56,373 +=========== =========== +6. ACCRUED EXPENSES +Accrued expenses consisted of the following at December 31, 2001 and 2000 +(in thousands): +2001 2000 +----------- ----------- +Salaries, wages, payroll taxes and benefits............... $ 13,833 $ 13,430 +Workers' compensation liability........................... 10,683 5,685 +Sales, use and other taxes................................ 4,758 2,803 +Insurance, other than workers' compensation............... 1,777 281 +Merger related costs...................................... 2,200 -- +Other..................................................... 3,257 1,879 +----------- ----------- +$ 36,508 $ 24,078 +=========== =========== +F-16 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +7. NOTES PAYABLE +The Company had no outstanding notes payable at December 31, 2001. Notes +payable consisted of the following at December 31, 2000 (in thousands): +2000 +--------- +Revolving credit facility................................... $ 50,710 +Non-revolving credit facility............................... 24,416 +Promissory notes............................................ 4,290 +--------- +79,416 +Less current maturities..................................... (4,477) +--------- +$ 74,939 +========= +On November 22, 1999, the Company entered into a $65.0 million revolving +credit facility. The maximum borrowings under this revolving credit facility +were increased to $75.0 million in May of 2000, to $90.0 million in October of +2000 and later increased to $100.0 million in June 2001 when the term of the +facility was also extended to June 2005. A fee of .375% per annum is assessed on +the unused facility amount. The amount used for letters of credit decreases the +borrowing base of the facility on a dollar-for-dollar basis. The revolving +credit facility calls for periodic interest payments at a floating rate ranging +from LIBOR plus 1.75% to 2.75%. Assets of the Company secure the facility. The +facility has restrictions customary in financial instruments of this type +including restrictions on certain investments, acquisitions and loans. The +facility has no financial covenants unless availability under the facility is +less than $20.0 million. There were no amounts drawn under the facility at +December 31, 2001. The terms of our facility limit the payment of dividends +without the prior written consent of the lenders. +During 2001, the Company repaid $89.2 million under its existing credit +facilities and other term obligations. The Company incurred expenses of $448,000 +as a result of prepayment penalties and $942,000 related to deferred financing +costs which were unamortized at the time the debt was extinguished. The +penalties and deferred financing costs are included in restructuring and related +charges for 2001. +The Company maintains letters of credit in the aggregate amount of $20.0 +million for the benefit of various insurance companies as collateral for +retrospective premiums and retained losses which could become payable under the +terms of the underlying insurance contracts. These letters of credit expire +variously during each calendar year, but provide for an indefinite number of +annual extensions of the expiration date. No amounts have been drawn under the +letters of credit. +8. COMMITMENTS, CONTINGENCIES AND OTHER MATTERS +Contingencies -- The Company's contract services and oil and natural gas +exploration and production operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in personal injury +or death, suspended drilling operations, damage to, or destruction of equipment, +damage to producing formations and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains general +liability insurance coverage of $2.0 million per occurrence with $4.0 million of +aggregate coverage and excess liability and umbrella coverages up to $50.0 +million per occurrence with a $50.0 million aggregate. +The Company believes it is adequately insured for public liability and +property damage to others with respect to its operations. However, such +insurance may not be sufficient to protect the Company against liability for all +consequences of well disasters, extensive fire damage or damage to the +environment. The Company also carries insurance to cover physical damage to, or +loss of, its rigs; however, it does not carry +F-17 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +8. COMMITMENTS, CONTINGENCIES AND OTHER MATTERS -- (CONTINUED) +insurance against loss of earnings resulting from such damage or loss. The +Company's lender who has a security interest in the drilling rigs is named as +loss payee on the physical damage insurance on such rigs. +Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc. +("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson +Petroleum LP and Patterson Drilling Company LP, in the Circuit Court, Rankin +County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter agreement +entered into in July 2000 between Patterson Petroleum and Westfort concerning +the drilling of a daywork well in Mississippi. This lawsuit was filed by +Westfort after Patterson Petroleum made demand on Westfort for payment of the +contract drilling services. +In this lawsuit, Westfort alleges breach of contract, fraud and negligence +causes of action. Westfort seeks alleged monetary damages, the return of shares +of Westfort stock, unspecified damages from alleged lost profits, lost use of +income stream and additional operating expenses, along with alleged punitive +damages to be determined by the jury, but not less than 25% of Patterson's net +worth. The Company intends to vigorously contest the allegations made by +Westfort and assert claims against Westfort, including for the monies owed +Patterson under the letter agreement in the amount of approximately $5,075,000. +In addition to the Westfort lawsuit, the Company is party to various legal +proceedings arising in the normal course of its business. The Company does not +believe that the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial condition. +9. STOCKHOLDERS' EQUITY +During December 2001, the Company issued 450,000 shares of its common stock +and warrants to acquire an additional 325,000 shares at an exercise price of +$26.75 per share, as partial consideration for the acquisition of 17 drilling +rigs and related equipment from Cleere Drilling Company. The common stock was +recorded at $21.55 per share and the warrants were valued at $8.00 per +underlying share of common stock using the Black-Scholes option valuation model +(see Note 2). +On May 8, 2001, pursuant to the merger between Patterson and UTI, the +Company's stockholders approved an amendment to the Company's charter increasing +the number of authorized shares of the Company's common stock to 200 million. +On May 7, 2001, warrants to purchase 121,250 shares of UTI's common stock +were exercised. The exercise price ranged from $13.25 to $17.50. The $1.8 +million in proceeds resulting from the exercise was used as partial payment of +notes payable owed to the same parties. +During January 2001, the Company issued 810,070 shares of its common stock +as partial consideration for the acquisition of Jones Drilling Corporation and +certain assets owned by its related entities (see Note 2). The common stock was +valued at $26.8125 per share, its fair market value on the date of the +transaction. +During September 2000, the Company issued 3,000,000 shares of its common +stock at a public price of $34.50 per share. An underwriting discount of $1.50 +was paid for a net price of $33.00 per share. Net proceeds from the offering +totaled approximately $98.8 million. +During June 2000, the Company issued 1,150,000 shares of its common stock +and three-year warrants to acquire an additional 127,000 shares at an exercise +price of $22.00 per share, as consideration for certain drilling equipment +acquired from High Valley Drilling, Inc. (see Note 2). The common stock was +recorded at $18 per share, its fair market value on the date of purchase and the +warrants were valued at $900,000 using the Black-Scholes option valuation model. +F-18 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +9. STOCKHOLDERS' EQUITY -- (CONTINUED) +During March 2000, the Company issued 53,000 shares of its common stock as +consideration for certain drilling equipment acquired from WEK Drilling Company, +Inc. The common stock was recorded at $29.0625 per share, its fair market value +on the date of purchase (see Note 2). +During June 1999, the Company issued 25,776 shares of its common stock as +consideration for certain drilling equipment acquired from an unrelated entity. +The common stock was recorded at $8.0625 per share, its fair market value on the +date of purchase. +On January 27, 1999, the Company issued 800,000 shares of its common stock +as consideration for the Company's acquisition of the drilling assets of Padre +Industries, Inc. The common stock was recorded at its guaranteed value of $5.00 +per share, or an aggregate purchase price of $4.0 million. On February 1, 2000, +the Company exercised its option to buy back 300,000 shares of its common stock +previously issued in conjunction with this acquisition for $5.50 per share. +10. STOCK OPTIONS AND WARRANTS +Employee and Non-Employee Director Stock Option Plans. The Company has +seven stock option plans of which three are active. The remaining four plans are +dormant and the Company does not intend to grant any further options under such +plans. At December 31, 2001, the Company's stock option plans were as follows: +OPTIONS OPTIONS +AUTHORIZED OPTIONS AVAILABLE +PLAN NAME FOR GRANT OUTSTANDING FOR GRANT +--------- ---------- ------------- ------------- +Amended and Restated Non-Employee Director +Stock Option Plan of Patterson-UTI Energy, +Inc. ("Non-Employee Director Plan")(1)...... 600,000 165,000 360,000 +Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan ("2001 Plan")(2)............. 1,000,000 800,500 199,500 +Patterson-UTI Energy, Inc. Amended and +Restated 1997 Long-Term Incentive Plan +("1997 Plan")(1)(3)......................... 3,800,000 3,256,301 132,501 +Patterson-UTI Energy, Inc. Non-Employee +Directors' Stock Option Plan, as amended +("1995 Non-Employee Director Plan")......... 120,000 32,000 -- +1997 Stock Option Plan of DSI Industries, Inc. +("DSI Plan")(1)............................. -- 113,226 -- +Amended and Restated Patterson-UTI Energy, +Inc. 1996 Employee Stock Option Plan ("1996 +Plan")(1)................................... -- 1,005,300 -- +Patterson-UTI Energy, Inc., 1993 Incentive +Stock Plan, as amended ("1993 Plan")........ 2,800,000 1,199,965 -- +--------------- +(1) Plan was assumed by the Company as a part of the merger between Patterson +and UTI. +(2) Plan is for the benefit of employees of the Company, other than officers and +directors of the Company. +(3) Plan is for the benefit of employees of the Company, including officers and +directors of the Company. +The Company's active plans are the 1997 Plan, the 2001 Plan and the +Non-Employee Director Plan. A summary of each of these plans is set forth below. +F-19 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +1997 PLAN +- Administered by the Compensation Committee of the Board of Directors. +- All employees including officers and employee directors are eligible for +awards. +- Vesting schedule is set by the Compensation Committee, however, typically +20% of the options vest after one year and the remaining 80% vest monthly +over the next four years. +- The Compensation committee sets the term of the option except that no +Incentive Stock Option ("ISO") can have a term of longer than 10 years. +Typically options granted under the plan have a term of 10 years. +- The options granted under the plan, unless otherwise stated in the grant +thereof, vest upon a change of control as defined in the plan. Options +granted to non-executive employees typically do not vest upon a change of +control. +- All options granted under the plan are granted with an exercise price +equal to or greater than the fair market value of the Company's common +stock at the time the option is granted. +- Although the plan allows for awards of tandem and independent stock +appreciation rights, restricted stock and performance awards, no such +awards have been granted. +2001 PLAN +The terms and conditions of the 2001 Plan are identical to the 1997 Plan +except as follows: +- Officers and directors of the Company are not eligible for grants of +options under the 2001 Plan. +- No ISO's may be awarded under the 2001 Plan. +- Unless the grant states otherwise, options granted under the 2001 Plan do +not vest upon a change of control of the Company. +NON-EMPLOYEE DIRECTOR PLAN +- Administered by the Compensation Committee of the Board of Directors. +- All options vest upon the first anniversary of the option grant. +- Each director receives options to purchase 15,000 shares upon becoming a +director of the Company and options to purchase 7,500 shares on December +31 of each subsequent year in which the director serves as a director of +the Company. +- The exercise price of the options is the fair market value of the +Company's common stock on the date of the grant. +Of the four dormant plans administered by the Company, two of the plans +(the 1993 Plan and the 1995 Non-Employee Director Plan) were plans of the +Company prior to the merger of Patterson and UTI and two of the plans (the DSI +Plan and the 1996 Plan) were plans of UTI. +1993 Plan. Options granted under the 1993 Plan, typically had terms of 10 +years and vested over five years in 20% increments beginning at the end of the +first year. These options vest in the event of a change of control as defined in +the plan. All options were granted with an exercise price equal to the fair +market value of the Company's common stock at the time of grant. +F-20 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +1995 Non-Employee Director Plan. All options granted under the 1995 +Non-Employee Director Plan were vested as of November 6, 2001. 1995 Non-Employee +Director Plan options have five year terms. All options were granted with an +exercise price equal to the fair market value of the Company's common stock at +the time of grant. +DSI Plan. The options granted under the DSI plan typically vested at a +rate of 33% per year with ten year terms. All options were granted with an +exercise price equal to the fair market value of the Company's common stock at +the time of grant. +1996 Plan. The options granted under the 1996 plan vested over one, four +and five years as dictated by the Compensation Committee. These options had +terms of five and ten years as dictated by the Compensation Committee. All +options were granted with a strike price equal to the fair market value of the +Company's common stock at the time of grant. +Additional Options. In July 2001, the Compensation Committee granted to +each of two non-employee directors of the Company an option to purchase 12,000 +shares of the Company's Common Stock. These options vested on November 6, 2001 +and terminate four years later on November 5, 2005. The exercise price of each +of the options was $28.625 which was in excess of the fair market value of the +Company's common stock on the date of grant. +A summary of the status of the Company's stock options issued under its +various incentive plans as of December 31, 2001, 2000 and 1999 and the changes +during each of the years then ended are presented below (in thousands, except +weighted average exercise price): +2001 2000 1999 +--------------------------- --------------------------- --------------------------- +NO. OF NO. OF NO. OF +SHARES OF WEIGHTED SHARES OF WEIGHTED SHARES OF WEIGHTED +UNDERLYING AVERAGE UNDERLYING AVERAGE UNDERLYING AVERAGE +OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE +---------- -------------- ---------- -------------- ---------- -------------- +Outstanding at beginning of +the year................... 5,488 $ 7.57 6,497 $ 5.72 5,334 $ 5.38 +Granted.................... 2,103 16.19 586 18.58 2,644 4.76 +------- -------- ------- -------- ------- -------- +Total granted...... 7,591 9.96 7,083 6.78 7,978 5.18 +Exercised.................. 805 5.26 1,563 3.93 1,249 1.77 +Surrendered................ 190 14.39 32 11.42 232 8.35 +------- -------- ------- -------- ------- -------- +Outstanding at end of year... 6,596 $ 10.40 5,488 $ 7.57 6,497 $ 5.72 +======= ======== ======= ======== ======= ======== +Exercisable at end of year... 4,110 $ 7.52 2,672 $ 6.89 3,019 $ 5.52 +======= ======== ======= ======== ======= ======== +The following table summarizes information about stock options outstanding +at December 31, 2001: +OPTIONS OUTSTANDING OPTIONS EXERCISABLE +------------------------------------------------- ------------------------------ +WEIGHTED AVERAGE +NUMBER REMAINING WEIGHTED AVERAGE NUMBER WEIGHTED AVERAGE +RANGE OF EXERCISE PRICES OUTSTANDING CONTRACTED LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICES +------------------------ ----------- ---------------- ---------------- ----------- ---------------- +$1.81 to $5.00............ 3,023,371 4.26 $ 4.59 2,801,904 $ 4.57 +$5.01 to $20.00........... 3,427,921 8.24 $ 14.84 1,208,354 $ 12.67 +$20.01 to $32.875......... 145,000 5.07 $ 26.51 100,000 $ 27.95 +----------- ------ -------- ----------- -------- +6,596,292 6.35 $ 10.40 4,110,258 $ 7.52 +=========== ====== ======== =========== ======== +F-21 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +Public Relations Services Stock Options -- In June 1999, the Company issued +options covering a total of 50,000 shares of common stock at an exercise price +of $8.0625 per share to a consultant as partial compensation for public +relations services rendered to the Company. The options granted to the +consultant have an exercise price equal to the fair market value of the stock at +date of grant. The options were fully exercisable upon grant date. The Company +accounted for the option grant in accordance with SFAS No. 123, and as such, a +charge for stock compensation expense of $250,000, which represents the fair +value of the options on the date of grant, is included in general and +administrative expenses for the year ended December 31, 1999. All such options +were exercised in 2000. +Pro Forma Stock-Based Compensation Disclosure -- SFAS 123 requires that pro +forma information regarding net income and earnings per share be presented as if +the Company had accounted for its employee stock options under the fair value +method as defined in that statement. The fair value of each stock option granted +is estimated on the date of grant using the Black-Scholes option valuation model +with the following weighted-average assumptions for grants in 1995, 1996, 1997, +1998, 1999, 2000 and 2001 respectively; dividend yield of 0.00%; risk-free +interest rates are different for each grant and range from 4.65% to 7.02%; the +expected term is 5 years; and a volatility of 38.68% for all 1995 and 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 and 68.33% for all 2001 grants. The +effects of applying SFAS No. 123 in this pro forma disclosure are not indicative +of future amounts. SFAS No. 123 does not apply to awards prior to 1995. +For purposes of pro forma disclosures, the estimated fair value of the +options is amortized to expense over the options' vesting period. The Company's +pro forma information follows: +YEARS ENDED DECEMBER 31, +----------------------------------------- +2001 2000 1999 +------------ ------------ ----------- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +Pro forma net income (loss)............................. $ 157,109 $ 31,210 $ (17,691) +========== ========== ========= +Pro forma earnings (loss) per share: +Basic................................................... $ 2.06 $ 0.44 $ (0.27) +========== ========== ========= +Diluted................................................. $ 1.98 $ 0.42 $ (0.27) +========== ========== ========= +Weighted-average fair value of options granted per +share................................................. $ 9.97 $ 15.73 $ 3.07 +A summary of Patterson-UTI's stock option activity and related information for +the years ended December 31 follows: +Stock Purchase Warrants -- In December 2001, the Company issued 325,000 +warrants exercisable at $26.75 per share as partial consideration for the +purchase of 17 drilling rigs and related equipment from Cleere Drilling Company +(see Note 2). The warrants were fully exercisable upon the date of issuance. If +not exercised, the warrants will expire on December 21, 2004. +In June 2000, the Company issued 127,000 warrants exercisable at $22 per +share as partial consideration for the purchase of eight drilling rigs and +related equipment from High Valley Drilling, Inc. (see Note 2). The warrants +were fully exercisable upon date of issuance. If not exercised, the warrants +will expire on June 2, 2003. +F-22 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCK OPTIONS AND WARRANTS -- (CONTINUED) +Tabular Summary -- The following table summarizes information regarding the +Company's stock options and warrants granted under the provisions of the +aforementioned plans: as well as stock options and warrants issued pursuant to +certain transactions described in Notes 2 and 9: +WEIGHTED AVERAGE +SHARES EXERCISE PRICE +--------- ---------------- +GRANTED +2001.................................................... 2,428,500 $ 17.60 +2000.................................................... 713,000 19.19 +1999.................................................... 2,643,754 4.76 +EXERCISED +2001.................................................... 804,581 $ 5.26 +2000.................................................... 1,563,345 3.93 +1999.................................................... 1,248,880 1.77 +SURRENDERED +2001.................................................... 190,473 $ 14.39 +2000.................................................... 31,879 11.42 +1999.................................................... 231,862 8.35 +OUTSTANDING AT YEAR END +2001.................................................... 7,048,292 $ 11.36 +2000.................................................... 5,614,846 7.89 +1999.................................................... 6,497,070 5.72 +EXERCISABLE AT YEAR END +2001.................................................... 4,562,259 $ 9.29 +2000.................................................... 2,799,482 7.58 +1999.................................................... 3,018,835 5.52 +11. LEASES +The Company incurred rent expense, consisting primarily of daily rental +charges for the use of drilling equipment of $5.9 million, $8.6 million and $5.6 +million, for the years 2001, 2000 and 1999, respectively. The Company's +obligations under non-cancelable operating lease agreements are not material to +the Company's operations. +F-23 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +12. INCOME TAXES +Components of the income tax provision applicable for federal and state +income taxes are as follows (in thousands): +2001 2000 1999 +---------- --------- --------- +Federal income tax expense (benefit): +Current........................................ $ 82,417 $ 6,932 $ (264) +Deferred....................................... 10,887 14,705 (4,827) +---------- --------- --------- +93,304 21,637 (5,091) +State income tax expense: +Current........................................ 4,294 (1) 398 +Deferred....................................... 661 772 (73) +---------- --------- --------- +4,955 771 325 +Foreign income tax expense: +Current........................................ 1,062 -- -- +Deferred....................................... 3,012 470 -- +---------- --------- --------- +4,074 470 -- +Total: +Current........................................ 87,773 6,931 134 +Deferred....................................... 14,560 15,947 (4,900) +---------- --------- --------- +Total income tax expense (benefit)............... $ 102,333 $ 22,878 $ (4,766) +========== ========= ========= +The difference between the statutory federal income tax rate and the +effective income tax rate is summarized as follows: +2001 2000 1999 +---- ---- ----- +Statutory tax rate.......................................... 35.0% 35.0% (34.2)% +State income taxes.......................................... 1.9 1.0 1.3 +Foreign taxes............................................... -- 0.2 -- +Permanent differences....................................... 1.3 1.4 3.9 +Other, net.................................................. 0.2 .5 0.1 +---- ---- ----- +Effective tax rate.......................................... 38.4% 38.1% (28.9)% +==== ==== ===== +In assessing the realizability of deferred tax assets, management considers +whether it is more likely than not that some portion or all of the deferred tax +assets will not be realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during the periods in +which those temporary differences become deductible. Management considers the +scheduled reversal of deferred tax liabilities, projected future taxable income, +and tax planning strategies in making this assessment. The Company expects the +deferred tax assets at December 31, 2001 to be realized as a result of the +reversal during the carryforward period of existing taxable temporary +differences giving rise to deferred tax liabilities and the generation of +taxable income in the carryforward period; therefore, no valuation allowance is +necessary. +F-24 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +12. INCOME TAXES -- (CONTINUED) +The tax effect of significant temporary differences representing deferred +tax assets and liabilities and changes therein were as follows (in thousands): +DECEMBER 31, NET DECEMBER 31, NET DECEMBER 31, NET JANUARY 1, +2001 CHANGE 2000 CHANGE 1999 CHANGE 1999 +------------ ------ ------------ ------ ------------ ------ ---------- +Deferred tax assets: +Net operating loss +carryforwards................. $ -- $ (5,850) $ 5,850 $ (5,878) $ 11,728 $ 10,294 $ 1,434 +Investment tax credit +carryforwards................. -- (469) 469 73 396 (163) 559 +AMT credit carryforwards......... 602 (3,770) 4,372 543 3,829 3,511 318 +Other............................ 8,145 2,791 5,354 2,215 3,139 166 2,973 +------------ ---------- ---------- ---------- ---------- ---------- ---------- +8,747 (7,298) 16,045 (3,047) 19,092 13,808 5,284 +Valuation allowance.............. -- -- -- -- -- -- -- +------------ ---------- ---------- ---------- ---------- ---------- ---------- +Deferred tax assets............. 8,747 (7,298) 16,045 (3,047) 19,092 13,808 5,284 +Deferred tax liabilities: +Property and equipment basis +difference.................... (92,859) (16,005) (76,854) (17,132) (59,722) (14,815) (44,907) +------------ ---------- ---------- ---------- ---------- ---------- ---------- +Net deferred tax +liability............... $ (84,112) $ (23,303) $ (60,809) $ (20,179) $ (40,630) $ (1,007) $ (39,623) +============ ========== ========== ========== ========== ========== ========== +Patterson-UTI's investment tax credit carryforward expired in 2000, the +expiration of which gave rise to a deduction of 50% of the credit in 2001. Net +operating losses were fully utilized in 2001 and the remaining alternative +minimum tax credit may be carried forward indefinitely. Significant other +deferred tax assets consist primarily of workers' compensation allowance of $4.5 +million and bad debt allowance of $1.3 million at December 31, 2001. +13. EMPLOYEE BENEFITS +The Company maintains a 401(k) profit sharing plan for all eligible +employees. Company contributions are discretionary. The Company made no matching +contribution in 1999, but made matching contributions of $789,000 and $2.1 +million for 2001 and 2000, respectively. +14. BUSINESS SEGMENTS +The Company conducts its business through three distinct operating +activities: contract drilling of oil and natural gas wells, and provision of +drilling and completion fluids services and pressure pumping services to +operators in the oil and natural gas industry. +Contract Drilling Services. The Company markets its contract drilling +services to major and independent oil and natural gas producers and operators. +The Company owns 319 drilling rigs, of which 287 operated in 2001. Currently, +257 of the drilling rigs are based in Texas and New Mexico (144 in West Texas +and New Mexico, 53 in South Texas, 39 in East Texas and 21 in North-Central +Texas), 41 are based in Oklahoma, five in Utah and 16 in western Canada. Our +contract drilling services operations contributed operating income of $274.5 +million in 2001. +Drilling and Completion Fluids Services. The Company provides contract +drilling and completion fluids services to oil and natural gas producers in the +Permian Basin of West Texas and Southeast New Mexico, South Texas, East Texas, +Oklahoma, the Gulf Coast regions of Texas and Louisiana, and the Gulf of Mexico. +Drilling and completion fluids are used by oil and natural gas operators during +the drilling process to control pressure when drilling oil and natural gas +wells. The drilling fluids operations were added by the Company during 1998 with +its acquisition of two companies with operations in Texas, New Mexico, Oklahoma +and +F-25 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +14. BUSINESS SEGMENTS -- (CONTINUED) +Colorado. Our services were expanded to include completion fluids in October +2000 with the acquisition of the drilling and completion fluids division of +Ambar, Inc., which had operations in the coastal areas of Texas, Louisiana and +in the Gulf of Mexico. Our drilling and completion fluids services operations +contributed operating income of $3.8 million in 2001. +Pressure Pumping Services. The Company provides pressure pumping services +in the Appalachian Basin. Pressure pumping services consist primarily of well +stimulation and cementing for the completion of new wells and remedial work on +existing wells. Well stimulation involves processes inside a well designed to +enhance the flow of oil, natural gas or other desired substances from the well. +Cementing is the process of inserting material between the hole and the pipe to +center and stabilize the pipe in the hole. Our pressure pumping services +operations contributed operating income of $12.6 million in 2001. +The following table summarizes selected financial information relating to +our business segments: +DECEMBER 31, +------------------------------------ +2001 2000 1999 +---------- ---------- ---------- +(IN THOUSANDS) +Revenues: +Contract drilling.................................... $ 839,931 $ 512,998 $ 266,212 +Drilling and completion fluids....................... 94,456 32,053 11,686 +Pressure pumping..................................... 39,600 21,465 20,721 +Other................................................ 15,988 15,806 8,747 +---------- ---------- ---------- +Total revenues......................................... $ 989,975 $ 582,322 $ 307,366 +========== ========== ========== +Income (loss) from operations: +Contract drilling.................................... $ 274,514 $ 68,427 $ (10,427) +Drilling and completion fluids....................... 3,842 (250) (1,279) +Pressure pumping..................................... 12,649 3,302 3,654 +Merger costs......................................... (5,943) -- -- +Restructuring and related charges.................... (7,202) -- -- +Other................................................ (10,688) (2,894) (1,398) +---------- ---------- ---------- +267,172 68,585 (9,450) +Interest income...................................... 2,080 1,377 1,047 +Interest expense..................................... (3,142) (10,108) (8,269) +Other................................................ 385 250 169 +---------- ---------- ---------- +Income (loss) before income taxes...................... $ 266,495 $ 60,104 $ (16,503) +========== ========== ========== +F-26 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +14. BUSINESS SEGMENTS -- (CONTINUED) +DECEMBER 31, +------------------------------------ +2001 2000 1999 +---------- ---------- ---------- +(IN THOUSANDS) +Identifiable assets: +Contract drilling.................................... $ 681,700 $ 571,498 $ 423,834 +Drilling and completion fluids....................... 41,724 52,414 19,117 +Pressure pumping..................................... 29,473 16,114 16,399 +Corporate and other (a).............................. 116,745 99,872 37,365 +---------- ---------- ---------- +Total assets........................................... $ 869,642 $ 739,898 $ 496,715 +========== ========== ========== +Depreciation, depletion and amortization: +Contract drilling.................................... $ 72,797 $ 54,274 $ 46,907 +Drilling and completion fluids....................... 2,644 1,464 1,065 +Pressure pumping..................................... 1,895 1,564 1,391 +Corporate and other.................................. 8,823 4,162 3,190 +---------- ---------- ---------- +Total depreciation, depletion and amortization......... $ 86,159 $ 61,464 $ 52,553 +========== ========== ========== +Capital expenditures: +Contract drilling.................................... $ 150,788 $ 116,836 $ 25,033 +Drilling and completion fluids....................... 4,937 10,166 195 +Pressure pumping..................................... 7,756 4,426 2,307 +Corporate and other.................................. 13,276 5,341 5,281 +---------- ---------- ---------- +Total capital expenditures............................. $ 176,757 $ 136,769 $ 32,816 +========== ========== ========== +--------------- +(a) Corporate assets primarily include cash on hand managed by the parent +corporation and certain deferred Federal income tax assets. +F-27 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +15. SELECTED QUARTERLY FINANCIAL RESULTS (UNAUDITED) +Quarterly financial information for the years ended December 31, 2001 and +2000 is as follows: +1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL +----------- ----------- ----------- ----------- ---------- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +2001 +Operating +revenues......... $ 238,586 $ 287,564 $ 289,104 $ 174,721 $ 989,975 +Operating income +(loss)........... 59,160 79,249 98,872 29,891 267,172 +Net income (loss)... 36,611 48,466 60,382 18,703 164,162 +Earnings per share: +Basic............... $ 0.49 $ 0.63 $ 0.79 $ 0.24 $ 2.15 +Diluted............. $ 0.45 $ 0.61 $ 0.77 $ 0.24 $ 2.07 +2000 +Operating +revenues......... $ 112,591 $ 123,339 $ 149,148 $ 197,244 $ 582,322 +Operating income +(loss)........... 3,907 9,777 19,996 34,905 68,585 +Net income (loss)... 1,091 4,627 10,293 21,215 37,226 +Earnings per share: +Basic............... $ 0.02 $ 0.07 $ 0.14 $ 0.29 $ 0.52 +Diluted............. $ 0.03 $ 0.06 $ 0.14 $ 0.27 $ 0.50 +16. CONCENTRATIONS OF CREDIT RISK +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand deposits, temporary +cash investments and trade receivables. +The Company believes that it places its demand deposits and temporary cash +investments with high credit quality financial institutions. At December 31, +2001 and 2000, the Company's demand deposits and temporary cash investments +consisted of the following (in thousands): +2001 2000 +---------- ---------- +Deposit in FDIC and SIPC-insured institutions under $100,000 +and cash on hand.......................................... $ 5,416 $ 1,653 +Deposit in FDIC and SIPC-insured institutions over $100,000 +and cash on hand.......................................... 39,057 69,376 +---------- ---------- +44,473 71,029 +Less outstanding checks and other reconciling items......... (10,889) (11,674) +---------- ---------- +Cash and cash equivalents................................... $ 33,584 $ 59,355 +========== ========== +Concentrations of credit risk with respect to trade receivables are +primarily focused on companies involved in the exploration and development of +oil and natural gas properties. The concentration is somewhat mitigated by the +diversification of customers for which the Company provides drilling services. +As is general industry practice, the Company generally does not require +customers to provide collateral. No significant losses from individual contracts +were experienced during the years ended December 31, 2001, 2000 and 1999. We +recognized bad debt expense for 2001, 2000 and 1999 of $2.0 million, $570,000 +and $282,000, respectively. +The carrying values of cash and cash equivalents, marketable securities and +trade receivables approximate fair value due to the short-term maturity of these +assets. +F-28 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +17. RELATED PARTY TRANSACTIONS +Use of Assets -- In 2001, 2000 and 1999, the Company leased a 1981 Beech +King-Air 90 airplane owned by an affiliate of the Company's Chief Executive +Officer and our President/Chief Operating Officer. Under the terms of the lease, +the Company paid a monthly rental of $9,200 and its proportionate share of the +costs of fuel, insurance, taxes and maintenance of the aircraft. The Company +paid approximately $212,283, $193,769 and $222,583 for the lease of the airplane +during 2001, 2000 and 1999, respectively. +Sales of Oil -- An affiliate acted as the first purchaser of oil produced +from certain leases operated by the Company during 1999. Sales of oil to that +entity, both royalty and working interest were approximately $8.4 million. There +were no sales of oil to that entity in 2001 or 2000. +Joint Operation of Oil and Natural Gas Properties -- The Company operates +certain oil and natural gas properties in which the Chief Executive Officer, the +President/Chief Operating Officer, the Chief Financial Officer and other persons +or entities related to the Company purchased a joint interest ownership with the +Company and other industry partners. The Company made oil and natural gas +production payments (net of royalty) of $8.3 million, $13.4 million and $6.1 +million from these properties in 2001, 2000 and 1999, respectively, to the +aforementioned persons or entities. These persons or entities reimbursed the +Company for joint operating costs of $5.9 million, $8.0 million and $5.9 million +in 2001, 2000 and 1999, respectively. +Other -- In 2001, the Company paid approximately $387,000 to an entity +owned by a relative of the Company President/Chief Operating Officer for certain +equipment and metal fabrication services. One of our directors is a director and +an officer of a company from which we purchased drill pipe, materials and +supplies totalling approximately $22.0 million in 2001. This same director was +an officer of a customer through February 2001 from which we received +approximately $500,000 in revenues in 2001. +F-29 +PATTERSON-UTI ENERGY, INC. +SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS +ADDITIONS(1) +------------------------ +CHARGED TO ACQUIRED +BEGINNING COSTS AND THROUGH ENDING +DESCRIPTION BALANCE EXPENSES ACQUISITION DEDUCTIONS(2) BALANCE +----------- --------- ---------- ----------- ------------- ------- +(IN THOUSANDS) +YEAR ENDED DECEMBER 31, 2001 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,462 $2,045 $ -- $1,486 $4,021 +YEAR ENDED DECEMBER 31, 2000 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,508 $ 570 $800 $1,416 $3,462 +YEAR ENDED DECEMBER 31, 1999 +Deducted from asset accounts: +Allowance for doubtful accounts....... $2,337 $ 282 $942 $ 53 $3,508 +--------------- +(1) Net of recoveries. +(2) Uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this report to +be signed on its behalf by the undersigned, thereunto duly authorized. +Date: March 18, 2002 PATTERSON-UTI ENERGY, INC. +By: /s/ CLOYCE A. TALBOTT +------------------------------------ +Cloyce A. Talbott +Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this +report has been signed by the following persons on behalf of Patterson-UTI +Energy, Inc. and in the capacities indicated as of March 18, 2002. +SIGNATURE TITLE +--------- ----- +/s/ MARK S. SIEGEL Chairman of the Board +-------------------------------------------------------- +Mark S. Siegel +/s/ CLOYCE A. TALBOTT Chief Executive Officer and Director +-------------------------------------------------------- +Cloyce A. Talbott +(Principal Executive Officer) +/s/ A. GLENN PATTERSON President, Chief Operating Officer and +-------------------------------------------------------- Director +A. Glenn Patterson +/s/ JONATHAN D. NELSON Vice President -- Finance, Chief +-------------------------------------------------------- Financial Officer, Secretary and +Jonathan D. Nelson Treasurer +(Principal Accounting Officer) +/s/ KENNETH N. BERNS Director +-------------------------------------------------------- +Kenneth N. Berns +/s/ VAUGHN E. DRUM Director +-------------------------------------------------------- +Vaughn E. Drum +Director +-------------------------------------------------------- +Nadine C. Smith +/s/ CURTIS W. HUFF Director +-------------------------------------------------------- +Curtis W. Huff +/s/ ROBERT C. GIST Director +-------------------------------------------------------- +Robert C. Gist +/s/ SPENCER D. ARMOUR, III Director +-------------------------------------------------------- +Spencer D. Armour, III +/s/ KENNETH R. PEAK Director +-------------------------------------------------------- +Kenneth R. Peak +/s/ STEPHEN J. DEGROAT Director +-------------------------------------------------------- +Stephen J. DeGroat +EXHIBIT INDEX +EXHIBIT +NUMBER DESCRIPTION +------- ----------- +2.1 Plan and Agreement of Merger dated October 14, 1993, between +Patterson Energy, Inc., a Texas corporation, and Patterson +Energy, Inc., a Delaware corporation, together with related +Certificates of Merger.(1) +2.2 Agreement and Plan of Merger, dated April 22, 1996 among +Patterson Energy, Inc., Patterson Drilling Company and +Tucker Drilling Company, Inc.(2) +2.2.1 Amendment to Agreement and Plan of Merger, dated May 16, +1996 among Patterson Energy, Inc., Patterson Drilling +Company and Tucker Drilling Company, Inc.(3) +2.3 Agreement and Plan of Merger dated as of January 5, 2001 +among Patterson Energy, Inc., Patterson Drilling Company LP, +LLLP and Jones Drilling Corporation.(4) +2.4 Agreement and Plan of Merger, dated February 4, 2001, by and +between UTI Energy Corp. and Patterson Energy, Inc.(5) +2.5 Asset Purchase Agreement, dated as of December 21, 2001 +among Patterson-UTI Energy, Inc., Patterson-UTI Drilling +Company LP, LLLP and Cleere Drilling Company. +3.1 Restated Certificate of Incorporation.(6) +3.1.1 Certificate of Correction of Restated Certificate of +Incorporation. +3.2 Amended and Restated Bylaws. +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(7) +3.3.1 Amendment to Rights Agreement dated as of October 23, +2001.(15) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson-UTI Energy, Inc. regarding authorized Common Stock +and Preferred Stock.(14) +4.2 Certificate of Designation.(16) +4.2.1 Amendment to Certificate of Designation. +4.3 Registration Rights Agreement with Bear, Stearns and Co. +Inc., dated March 25, 1994, as assigned to REMY Capital +Partners III, L.P. +10.1 Loan and Security Agreement, dated November 22, 1999.(14) +10.1.1 First Amendment to Loan and Security Agreement, dated May 2, +2000.(14) +10.1.2 Second Amendment to Loan and Security Agreement, dated May +18, 2000.(14) +10.1.3 Third Amendment to Loan and Security Agreement, dated +October 18, 2000.(14) +10.1.4 Fourth Amendment to Loan and Security Agreement, dated May +8, 2001.(14) +10.1.5 Fifth Amendment to Loan and Security Agreement, dated June +29, 2001.(14) +10.1.6 Revolving Loan Promissory Note, dated June 29, 2001.(14) +10.1.7 Guaranty Agreement, dated June 29, 2001.(14) +10.1.8 Pledge Agreement, dated June 29, 2001.(14) +10.2 Aircraft Lease, dated December 20, 2000, (effective January +1, 2001) between Talbott Aviation, Inc. and Patterson +Energy, Inc.(8) +10.3 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as +amended.(9) +10.4 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended.(10) +10.5 Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan.(11) +EXHIBIT +NUMBER DESCRIPTION +------- ----------- +10.6 Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc.(12) +10.7 Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan.(12) +10.8 1997 Stock Option Plan of DSI Industries, Inc.(11) +10.9 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.). +10.10 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Stephen J. DeGroat (a +non-employee director of Patterson-UTI Energy, Inc.). +10.11 Model Form Operating Agreement.(13) +10.12 Form of Drilling Bid Proposal and Footage Drilling +Contract.(13) +10.13 Form of Turnkey Drilling Agreement.(13) +21.1 Subsidiaries of the Registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Auditors -- Ernst & Young LLP. +--------------- +(1) Incorporated herein by reference to Item 27, "Exhibits" to Amendment No. 2 +to Registration Statement on Form SB-2 (File No. 33-68058-FW) filed on +October 28, 1993. +(2) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated April 22, 1996 and filed on April 30, 1996. +(3) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated May 16, 1996 and filed on May 22, 1996. +(4) Incorporated by reference to Item 16, "Exhibits" to Registration Statement +on Form S-3 filed on January 8, 2001. +(5) Incorporated herein by reference to Joint Proxy Statement/Prospectus filed +on March 14, 2001. +(6) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated and filed on May 8, 2001. +(7) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on For 8-A filed on January 14, 1997. +(8) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Form 10-K dated December 31, 2000. +(9) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 333-47917) filed on March 13, 1998. +(10) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on November 4, 1997. +(11) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470) +filed on July 25, 2001. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466) +filed on July 25, 2001. +(13) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993. +(14) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on +August 1, 2001. +(15) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed +on October 31, 2001. +(16) Incorporated herein by reference to Item 2, "Exhibits" to Registration +Statement on Form 8-A (File No. 000-22664) filed on January 14, 1997. \ No newline at end of file diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/filing_metadata.csv b/raw/filings/0000889900/2001/0000950134-02-002237/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..47256676c37348e949d81751ed454a33ef0fd96f --- /dev/null +++ b/raw/filings/0000889900/2001/0000950134-02-002237/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2002-03-19,2001-12-31,2002-03-19T05:00:00.000Z,0000950134-02-002237,d94131e10-k.txt,"FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2001",436018,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013402002237/d94131e10-k.txt,https://www.sec.gov/Archives/edgar/data/889900/000095013402002237/,2001,2001,1 diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/item1.txt b/raw/filings/0000889900/2001/0000950134-02-002237/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/item13.txt b/raw/filings/0000889900/2001/0000950134-02-002237/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..7430f1f5432043b17caf623ffc231c16e5b70cc7 --- /dev/null +++ b/raw/filings/0000889900/2001/0000950134-02-002237/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +28 \ No newline at end of file diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/item9a.txt b/raw/filings/0000889900/2001/0000950134-02-002237/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/rp_note.txt b/raw/filings/0000889900/2001/0000950134-02-002237/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..0b0ea5cc077ff0df38e1115b609c9394996cd14e --- /dev/null +++ b/raw/filings/0000889900/2001/0000950134-02-002237/rp_note.txt @@ -0,0 +1,226 @@ +17. RELATED PARTY TRANSACTIONS +Use of Assets -- In 2001, 2000 and 1999, the Company leased a 1981 Beech +King-Air 90 airplane owned by an affiliate of the Company's Chief Executive +Officer and our President/Chief Operating Officer. Under the terms of the lease, +the Company paid a monthly rental of $9,200 and its proportionate share of the +costs of fuel, insurance, taxes and maintenance of the aircraft. The Company +paid approximately $212,283, $193,769 and $222,583 for the lease of the airplane +during 2001, 2000 and 1999, respectively. +Sales of Oil -- An affiliate acted as the first purchaser of oil produced +from certain leases operated by the Company during 1999. Sales of oil to that +entity, both royalty and working interest were approximately $8.4 million. There +were no sales of oil to that entity in 2001 or 2000. +Joint Operation of Oil and Natural Gas Properties -- The Company operates +certain oil and natural gas properties in which the Chief Executive Officer, the +President/Chief Operating Officer, the Chief Financial Officer and other persons +or entities related to the Company purchased a joint interest ownership with the +Company and other industry partners. The Company made oil and natural gas +production payments (net of royalty) of $8.3 million, $13.4 million and $6.1 +million from these properties in 2001, 2000 and 1999, respectively, to the +aforementioned persons or entities. These persons or entities reimbursed the +Company for joint operating costs of $5.9 million, $8.0 million and $5.9 million +in 2001, 2000 and 1999, respectively. +Other -- In 2001, the Company paid approximately $387,000 to an entity +owned by a relative of the Company President/Chief Operating Officer for certain +equipment and metal fabrication services. One of our directors is a director and +an officer of a company from which we purchased drill pipe, materials and +supplies totalling approximately $22.0 million in 2001. This same director was +an officer of a customer through February 2001 from which we received +approximately $500,000 in revenues in 2001. +F-29 +PATTERSON-UTI ENERGY, INC. +SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS +ADDITIONS(1) +------------------------ +CHARGED TO ACQUIRED +BEGINNING COSTS AND THROUGH ENDING +DESCRIPTION BALANCE EXPENSES ACQUISITION DEDUCTIONS(2) BALANCE +----------- --------- ---------- ----------- ------------- ------- +(IN THOUSANDS) +YEAR ENDED DECEMBER 31, 2001 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,462 $2,045 $ -- $1,486 $4,021 +YEAR ENDED DECEMBER 31, 2000 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,508 $ 570 $800 $1,416 $3,462 +YEAR ENDED DECEMBER 31, 1999 +Deducted from asset accounts: +Allowance for doubtful accounts....... $2,337 $ 282 $942 $ 53 $3,508 +--------------- +(1) Net of recoveries. +(2) Uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this report to +be signed on its behalf by the undersigned, thereunto duly authorized. +Date: March 18, 2002 PATTERSON-UTI ENERGY, INC. +By: /s/ CLOYCE A. TALBOTT +------------------------------------ +Cloyce A. Talbott +Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this +report has been signed by the following persons on behalf of Patterson-UTI +Energy, Inc. and in the capacities indicated as of March 18, 2002. +SIGNATURE TITLE +--------- ----- +/s/ MARK S. SIEGEL Chairman of the Board +-------------------------------------------------------- +Mark S. Siegel +/s/ CLOYCE A. TALBOTT Chief Executive Officer and Director +-------------------------------------------------------- +Cloyce A. Talbott +(Principal Executive Officer) +/s/ A. GLENN PATTERSON President, Chief Operating Officer and +-------------------------------------------------------- Director +A. Glenn Patterson +/s/ JONATHAN D. NELSON Vice President -- Finance, Chief +-------------------------------------------------------- Financial Officer, Secretary and +Jonathan D. Nelson Treasurer +(Principal Accounting Officer) +/s/ KENNETH N. BERNS Director +-------------------------------------------------------- +Kenneth N. Berns +/s/ VAUGHN E. DRUM Director +-------------------------------------------------------- +Vaughn E. Drum +Director +-------------------------------------------------------- +Nadine C. Smith +/s/ CURTIS W. HUFF Director +-------------------------------------------------------- +Curtis W. Huff +/s/ ROBERT C. GIST Director +-------------------------------------------------------- +Robert C. Gist +/s/ SPENCER D. ARMOUR, III Director +-------------------------------------------------------- +Spencer D. Armour, III +/s/ KENNETH R. PEAK Director +-------------------------------------------------------- +Kenneth R. Peak +/s/ STEPHEN J. DEGROAT Director +-------------------------------------------------------- +Stephen J. DeGroat +EXHIBIT INDEX +EXHIBIT +NUMBER DESCRIPTION +------- ----------- +2.1 Plan and Agreement of Merger dated October 14, 1993, between +Patterson Energy, Inc., a Texas corporation, and Patterson +Energy, Inc., a Delaware corporation, together with related +Certificates of Merger.(1) +2.2 Agreement and Plan of Merger, dated April 22, 1996 among +Patterson Energy, Inc., Patterson Drilling Company and +Tucker Drilling Company, Inc.(2) +2.2.1 Amendment to Agreement and Plan of Merger, dated May 16, +1996 among Patterson Energy, Inc., Patterson Drilling +Company and Tucker Drilling Company, Inc.(3) +2.3 Agreement and Plan of Merger dated as of January 5, 2001 +among Patterson Energy, Inc., Patterson Drilling Company LP, +LLLP and Jones Drilling Corporation.(4) +2.4 Agreement and Plan of Merger, dated February 4, 2001, by and +between UTI Energy Corp. and Patterson Energy, Inc.(5) +2.5 Asset Purchase Agreement, dated as of December 21, 2001 +among Patterson-UTI Energy, Inc., Patterson-UTI Drilling +Company LP, LLLP and Cleere Drilling Company. +3.1 Restated Certificate of Incorporation.(6) +3.1.1 Certificate of Correction of Restated Certificate of +Incorporation. +3.2 Amended and Restated Bylaws. +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(7) +3.3.1 Amendment to Rights Agreement dated as of October 23, +2001.(15) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson-UTI Energy, Inc. regarding authorized Common Stock +and Preferred Stock.(14) +4.2 Certificate of Designation.(16) +4.2.1 Amendment to Certificate of Designation. +4.3 Registration Rights Agreement with Bear, Stearns and Co. +Inc., dated March 25, 1994, as assigned to REMY Capital +Partners III, L.P. +10.1 Loan and Security Agreement, dated November 22, 1999.(14) +10.1.1 First Amendment to Loan and Security Agreement, dated May 2, +2000.(14) +10.1.2 Second Amendment to Loan and Security Agreement, dated May +18, 2000.(14) +10.1.3 Third Amendment to Loan and Security Agreement, dated +October 18, 2000.(14) +10.1.4 Fourth Amendment to Loan and Security Agreement, dated May +8, 2001.(14) +10.1.5 Fifth Amendment to Loan and Security Agreement, dated June +29, 2001.(14) +10.1.6 Revolving Loan Promissory Note, dated June 29, 2001.(14) +10.1.7 Guaranty Agreement, dated June 29, 2001.(14) +10.1.8 Pledge Agreement, dated June 29, 2001.(14) +10.2 Aircraft Lease, dated December 20, 2000, (effective January +1, 2001) between Talbott Aviation, Inc. and Patterson +Energy, Inc.(8) +10.3 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as +amended.(9) +10.4 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended.(10) +10.5 Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan.(11) +EXHIBIT +NUMBER DESCRIPTION +------- ----------- +10.6 Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc.(12) +10.7 Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan.(12) +10.8 1997 Stock Option Plan of DSI Industries, Inc.(11) +10.9 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.). +10.10 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Stephen J. DeGroat (a +non-employee director of Patterson-UTI Energy, Inc.). +10.11 Model Form Operating Agreement.(13) +10.12 Form of Drilling Bid Proposal and Footage Drilling +Contract.(13) +10.13 Form of Turnkey Drilling Agreement.(13) +21.1 Subsidiaries of the Registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Auditors -- Ernst & Young LLP. +--------------- +(1) Incorporated herein by reference to Item 27, "Exhibits" to Amendment No. 2 +to Registration Statement on Form SB-2 (File No. 33-68058-FW) filed on +October 28, 1993. +(2) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated April 22, 1996 and filed on April 30, 1996. +(3) Incorporated by reference to Item 7, "Financial Statements and Exhibits" to +Form 8-K dated May 16, 1996 and filed on May 22, 1996. +(4) Incorporated by reference to Item 16, "Exhibits" to Registration Statement +on Form S-3 filed on January 8, 2001. +(5) Incorporated herein by reference to Joint Proxy Statement/Prospectus filed +on March 14, 2001. +(6) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated and filed on May 8, 2001. +(7) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on For 8-A filed on January 14, 1997. +(8) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Form 10-K dated December 31, 2000. +(9) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 333-47917) filed on March 13, 1998. +(10) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on November 4, 1997. +(11) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470) +filed on July 25, 2001. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466) +filed on July 25, 2001. +(13) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993. +(14) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on +August 1, 2001. +(15) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed +on October 31, 2001. +(16) Incorporated herein by reference to Item 2, "Exhibits" to Registration +Statement on Form 8-A (File No. 000-22664) filed on January 14, 1997. \ No newline at end of file diff --git a/raw/filings/0000889900/2001/0000950134-02-002237/rpt_disclosure.txt b/raw/filings/0000889900/2001/0000950134-02-002237/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/filing.txt b/raw/filings/0000889900/2002/0000950134-03-001857/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..135fa065f7be5870e82b6483d306cba4af431b19 --- /dev/null +++ b/raw/filings/0000889900/2002/0000950134-03-001857/filing.txt @@ -0,0 +1,3791 @@ +10-K +1 +d02863e10vk.txt +FORM 10-K +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +UNITED STATES SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +--------------------- +FORM 10-K +--------------------- +(Mark One) +[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 +OR +[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM TO +COMMISSION FILE NUMBER 0-22664 +--------------------- +PATTERSON-UTI ENERGY, INC. +(Exact name of registrant as specified in its charter) +DELAWARE 75-2504748 +(State or other jurisdiction of (I.R.S. Employer +incorporation or organization) Identification No.) +4510 LAMESA HIGHWAY, SNYDER, TEXAS 79549 +(Address of principal executive offices) (Zip Code) +--------------------- +REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: +(915) 574-6300 +--------------------- +SECURITIES REGISTERED PURSUANT TO 12(b) OF THE ACT: NONE +SECURITIES REGISTERED PURSUANT TO 12(g) OF THE ACT: +(TITLE OF CLASS) +---------------- +Common Stock, $.01 Par Value +Indicate by check mark whether the registrant (1) has filed all reports +required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the +registrant was required to file such reports), and (2) has been subject to such +filing requirements for the past 90 days. Yes [X] No [ ] +Indicate by check mark if disclosure of delinquent filers pursuant to Item +405 of the Regulation S-K is not contained herein, and will not be contained, to +the best of the registrant's knowledge, in definitive proxy or information +statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K. [X] +The aggregate market value of the voting and non-voting common equity held +by non-affiliates of the registrant as of January 31, 2003 was $2,267,237,824, +calculated by reference to the closing price of $30.51 for the common stock on +the Nasdaq National Market on that date. +Indicate by check mark whether the registrant is an accelerated filer (as +defined in Rule 12b-2 of the Act). Yes [X] No [ ] +The aggregate market value of the voting and non-voting common equity held +by non-affiliates of the registrant as of June 28, 2002, the last business day +of the registrant's most recently completed second fiscal quarter was +$2,065,033,816, calculated by reference to the closing price of $28.23 for the +common stock on the Nasdaq National Market on that date. +As of January 31, 2003, the registrant had outstanding 80,086,023 shares of +common stock, $.01 par value, its only class of voting stock. +Documents incorporated by reference: +Proxy Statement for the 2003 Annual Meeting of Stockholders (Part III) +-------------------------------------------------------------------------------- +-------------------------------------------------------------------------------- +This Report on Form 10-K (including documents incorporated by reference +herein) contains statements with respect to our expectations and beliefs as to +future events. These types of statements are "forward-looking" and subject to +uncertainties. Readers are cautioned that such forward-looking statements should +be read in conjunction with our disclosures under the heading: "Forward Looking +Statements and Cautionary Statements for Purposes of the 'Safe Harbor' +Provisions of the Private Securities Litigation Reform Act of 1995" beginning on +page 13. +This report on Form 10-K, along with our quarterly reports on Form 10-Q, +current reports on Form 8-K, and amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are +available through our Internet website (www.patenergy.com) as soon as reasonably +practicable after we electronically file such material with, or furnish it to, +the SEC. +PART I +ITEMS 1 AND 2. BUSINESS AND PROPERTIES. +OVERVIEW +Based on publicly available information, we believe we are the second +largest owner of land-based drilling rigs in North America. Formed in 1978 and +reincorporated in 1993 as a Delaware corporation, we conduct our contract +drilling operations in: +- Texas, +- New Mexico, +- Oklahoma, +- Louisiana, +- Mississippi, +- Utah, and +- Western Canada (Alberta, British Columbia, and Saskatchewan). +As of December 31, 2002, we had a drilling fleet of 324 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 drilling fluids, completion fluids, and related services to oil +and natural gas operators in West Texas, Southeast New Mexico, South Texas, East +Texas, Oklahoma, the Gulf Coast regions of Texas and Louisiana, and the Gulf of +Mexico. Drilling and completion fluids are used by oil and natural gas operators +during the drilling process to control pressure when drilling oil and natural +gas wells. We provide pressure pumping services to oil and natural gas operators +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 are also engaged in the development, exploration, acquisition and production +of oil and natural gas. Our oil and natural gas operations are focused in +producing regions in West Texas, Southeast New Mexico and South Texas. +PATTERSON/UTI MERGER +Patterson Energy, Inc. ("Patterson") and UTI Energy Corp. ("UTI") +consummated a merger on May 8, 2001. The transaction was treated as a +reorganization within the meaning of Section 368 (a) of the Internal Revenue +Code of 1986, as amended, and accounted for as a pooling of interests for +financial accounting purposes. Historical financial statements and related +financial and statistical data contained in this Report have been restated to +provide for the retroactive effect of the merger. +1 +INDUSTRY SEGMENTS +Our revenues, operating profits and identifiable operating assets are +attributable to four industry segments: +- contract drilling, +- drilling and completion fluids services, +- pressure pumping services, and +- oil and natural gas development, exploration, acquisition and production. +With respect to these four segments: +- the contract drilling segment had operating profits in 2000, 2001 and +2002, +- the drilling and completion fluids segment had operating losses in 2000 +and 2002 and an operating profit in 2001, +- the pressure pumping segment had operating profits in 2000, 2001 and +2002, and +- the oil and natural gas segment had operating profits in 2000, 2001 and +2002. +See "Management's Discussion and Analysis of Financial Condition and +Results of Operations" and Note 15 of Notes to Consolidated Financial Statements +included as a part of Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +CONTRACT DRILLING OPERATIONS +GENERAL -- We market our contract drilling services to major and +independent oil and natural gas operators. As of December 31, 2002, we owned 324 +drilling rigs which are located in the following regions: +- 262 in Texas and New Mexico (1), +- 41 in Oklahoma, +- 5 in Utah, and +- 16 in Western Canada. +--------------- +(1) 144 in West Texas and New Mexico, 56 in South Texas, 42 in East Texas, +and 20 in North Central Texas. +Of our drilling rigs, 38 are SCR electric rigs and 286 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. Our drilling rigs have rated maximum depth capabilities +ranging from 4,000 feet to 30,000 feet. +Drilling rigs are typically equipped with: +- engines, +- drawworks or hoists, +- derricks or masts, +- pumps to circulate the drilling fluid, +- blowout preventers, +- drill string (pipe), and +- other related equipment. +2 +Over time, many of the components on a drilling rig are replaced or +rebuilt. We spend significant funds each year on an ongoing program of modifying +and upgrading our drilling rigs to ensure that our drilling equipment is well +maintained and competitive. During fiscal years 2002, 2001, and 2000, we +capitalized approximately $65 million, $151 million, and $117 million, +respectively, to maintain, 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. Our drilling +rigs are utilized for both developmental and exploratory drilling and can be +used for either vertical or horizontal drilling. +Our contract drilling operations depend on the availability of: +- drill pipe, +- bits, +- replacement parts and other related rig equipment, +- fuel, and +- qualified personnel, +some of which have been in short supply from time to time. +DRILLING CONTRACTS -- Most of our drilling contracts are with established +customers and are obtained on a competitive bid or negotiated basis. Typically, +the contracts are entered into for short-term periods and cover the drilling of +a single well or a series of wells. +The drilling contracts obligate us to provide and operate a drilling rig +and to pay certain operating expenses, including wages of drilling personnel and +necessary maintenance expenses. The contracts are subject to termination by the +customer on short notice, usually upon payment of a fee. We generally indemnify +our customers against claims by our employees and claims arising from surface +pollution caused by spills of fuel, lubricants, and other solvents within our +control. The customers generally indemnify us against claims arising from other +surface and subsurface pollution, except claims arising from our own 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 bids +for each contract depend upon: +- the location, depth, and anticipated complexity of the well, +- the on-site drilling conditions, +- the equipment to be used, +- our estimate of the risks involved, +- the estimated duration of the work to be performed, +- the 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, also known as the operator. The operator supervises the drilling of +the well. Our compensation is based on a negotiated rate per day during the +period the drilling rig is utilized. We generally receive a lower rate when the +drilling rig is moving, or when drilling operations are interrupted or +restricted by adverse weather conditions or other conditions beyond our control. +In addition, daywork contracts typically provide for a lump sum fee for the +mobilization and demobilization of the drilling rig. +3 +FOOTAGE CONTRACTS +Under footage contracts, we contract to drill a well to a certain depth +under specified conditions for a fixed price per foot. The customer provides +drilling fluids, casing, cementing, and well design expertise. These 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 margins over those that +would be attainable under a daywork contract. Margins are reduced and losses may +be incurred if the well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for a drilling +contractor than daywork contracts. Under footage contracts, the drilling +contractor assumes certain risks associated with loss of the well from fire, +blowouts, and other risks. +TURNKEY CONTRACTS +Under turnkey contracts, we contract to drill a well to a certain depth +under specified conditions for a fixed fee. In a turnkey arrangement, we are +required to bear the costs of services, supplies, and equipment beyond those +typically provided under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion fluids, casing, +cementing, and the technical well design and engineering services during the +drilling process. We would also assume certain risks associated with drilling +the well such as fires, blowouts, cratering of the well bore, and other such +risks. Compensation occurs only when the agreed scope of the work has been +completed which requires us to make significant 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 margins 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, margins +can be significantly reduced and losses incurred if complications or delays +occur during the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of drilling contracts: +daywork, footage, and turnkey. +The following table sets forth the approximate percentage of our drilling +revenues attributable to daywork, footage, and turnkey contracts for each of the +last three years: +YEAR ENDED DECEMBER 31, +------------------------ +TYPE OF REVENUES 2002 2001 2000 +---------------- ------ ------ ------ +Daywork..................................................... 82% 93% 65% +Footage..................................................... 11 3 24 +Turnkey..................................................... 7 4 11 +CONTRACT DRILLING ACTIVITY -- The following table sets forth certain +information regarding our contract drilling activity for each of the last three +years: +YEAR ENDED DECEMBER 31, +------------------------ +2002 2001 2000 +------ ------ ------ +Average rigs owned.......................................... 323 302 263 +Average rigs operating...................................... 126 211 173 +Average rig utilization rate (1)............................ 39% 70% 66% +Number of rigs operated..................................... 230 287 229 +Number of wells drilled..................................... 2,012 2,869 2,649 +--------------- +(1) Rig utilization is based on a 365-day year for rigs owned during 2001 and +2002, and a 366-day year for rigs owned in 2000. A rig is utilized when it +is operating or being moved, assembled, or dismantled under contract. +4 +DRILLING RIGS AND RELATED EQUIPMENT -- The following table provides certain +information about our drilling rigs as of December 31, 2002: +DEPTH RATING (FT.) MECHANICAL ELECTRIC +------------------ ---------- -------- +4,000 to 9,999.............................................. 52 -- +10,000 to 11,999............................................ 67 2 +12,000 to 14,999............................................ 114 6 +15,000 to 30,000............................................ 53 30 +--- --- +Totals................................................. 286 38 +=== === +At December 31, 2002, we owned 244 trucks and 285 trailers used to rig +down, transport, and rig up our drilling rigs. This reduces Patterson-UTI's +dependency upon third parties for these services and enhances the efficiency of +our contract drilling operations particularly in periods of high drilling rig +utilization. +Most repair work and overhauls of our drilling rig equipment are performed +at our yard facilities located in Texas, New Mexico, Oklahoma, and Western +Canada. +DRILLING AND COMPLETION FLUIDS OPERATIONS +GENERAL -- We provide drilling fluids, completion fluids, and related +services to oil and natural gas operators in West Texas, Southeast New Mexico, +South Texas, East Texas, Oklahoma, the Gulf Coast regions of Texas and +Louisiana, and the Gulf of Mexico. We serve our offshore customers through seven +stockpoints located along the Gulf of Mexico in Texas and Louisiana and our +land-based customers through seven stockpoints in Texas, Louisiana, Oklahoma, +and New Mexico. +DRILLING FLUIDS -- Drilling fluid products and systems are used to cool and +lubricate the bit during drilling operations, contain formation pressures +(thereby minimizing blowout risk), suspend and remove rock cuttings from the +hole, and maintain the stability of the wellbore. Technical services are +provided to ensure that the products and systems are applied effectively to +optimize drilling operations. +COMPLETION FLUIDS -- After a well is drilled it undergoes the completion +process wherein the well casing is set and cemented into place. At that point, +the drilling fluid services are complete, and the drilling fluids are circulated +out of the well and replaced with completion fluids. Completion fluids, also +known as clear brine fluids, are solids-free, clear salt solutions that have +high specific gravities. Combined with a range of specialty chemicals, these +fluids are used by operators to control bottom-hole pressures and to meet a +well's specific corrosion, inhibition, viscosity, and fluid loss requirements +during the completion and workover phases. +RAW MATERIALS -- Our drilling and completion fluids operations depend on +the availability of the following raw materials: +DRILLING COMPLETION +-------- ----------------- +barite calcium chloride +bentonite calcium bromide +zinc bromide +We obtain these raw materials through purchases made on the spot market and +supply contracts with producers of these raw materials. +BARITE GRINDING FACILITY -- We own and operate a barite grinding facility +equipped with two barite grinding mills located in Houma, Louisiana. We believe +the ability to process our own barite is critical to being competitive on the +Gulf Coast and in the Gulf of Mexico since barite accounts for a substantial +portion of the dollar volume for drilling fluids jobs in both of these areas. +Our grinding facility allows us to grind raw barite into the powder additive +used in drilling fluids. Owning this facility reduces our dependence upon third +parties in our supply of barite. Without the grinding mills we would be required +to purchase processed barite from +5 +third parties, including some of our competitors, which could result in higher +production costs and less efficient operations. +OTHER EQUIPMENT -- We own 27 trucks and 102 trailers and lease another 25 +trucks used to transport drilling and completion fluids and related equipment. +PRESSURE PUMPING OPERATIONS +GENERAL -- We provide pressure pumping services to oil and natural gas +operators 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. Most wells drilled in the Appalachian Basin require some +form of fracturing or other stimulation to enhance the flow of oil and natural +gas which is accomplished by pumping fluids under pressure into the well bore. +Generally, Appalachian Basin wells require cementing services before production +commences. Cementing is the process of inserting material between the wall of +the well bore and the casing to center and stabilize the casing. +EQUIPMENT -- Continuous maintenance of our pressure pumping equipment is +necessary as significantly all of the pressure pumping equipment is in use on a +regular basis. As of December 31, 2002, we operated the following pressure +pumping equipment: +- 16 cement pumper trucks, +- 22 fracturing pumper trucks, +- 19 nitrogen pumper trucks, +- 12 blender trucks, +- 10 bulk acid trucks, +- 24 bulk cement trucks, +- 6 bulk nitrogen trucks, +- 22 bulk sand trucks, and +- 8 connection trucks. +OIL AND NATURAL GAS OPERATIONS +GENERAL -- We are engaged in the development, exploration, acquisition, and +production of oil and natural gas. Our oil and natural gas operations are +focused in producing regions in West Texas, Southeast New Mexico, and South +Texas. Our strategy for our oil and natural gas operations is to increase our +reserve base primarily through developmental drilling, as well as selected +acquisitions of leasehold acreage and producing properties. +OIL AND NATURAL GAS RESERVES -- The following table sets forth estimates, +derived from reserve reports provided by M. Brian Wallace, an independent +petroleum engineer, of our proved developed reserves and estimated future net +revenues from our proved developed reserves as of December 31, 2002, 2001, and +2000. The estimates were based upon production histories, current market prices +for oil and natural gas, and other geologic, ownership, and engineering data +provided by us. The present values (discounted at 10% before income taxes) of +estimated future net revenues shown in the table are not intended to represent +the current market value of the estimated oil and natural gas reserves. For +further information concerning the present value of estimated future net +revenues from these proved developed reserves, see also Note 20 of Notes to +Consolidated Financial Statements included as a part of Item 8 of this Report. +Proved oil and natural gas reserves are the estimated quantities of oil and +natural gas which geological and engineering data demonstrate, with reasonable +certainty, to be recoverable in future years from known reservoirs under +existing economic and operating conditions. Reserves are considered proved if +economical productibility is supported by either actual production or conclusive +formation tests. Proved developed oil and natural gas reserves can be expected +to be recovered through existing wells with existing equipment and operating +methods. +6 +AS OF DECEMBER 31, +--------------------------- +2002 2001 2000 +------- ------- ------- +(IN THOUSANDS) +Proved Developed Reserves: +Oil (Bbls)............................................ 1,227 1,047 1,129 +Gas (Mcf)............................................. 6,240 4,634 3,880 +Total (BOE)........................................... 2,267 1,819 1,776 +Estimated future net revenues before income taxes....... $46,016 $19,597 $31,891 +Present value of estimated future net revenues before +income taxes, discounted at 10%....................... $32,308 $14,492 $22,801 +A barrel (Bbl) of oil is 42 U.S. gallons and represents the basic unit for +measuring production of crude oil and condensate. +An Mcf of natural gas refers to a volume of 1,000 cubic feet under +prescribed conditions of pressure and temperature and represents the basic unit +for measuring volumes of produced natural gas. A barrel of equivalent (BOE) in +reference to natural gas equivalents is determined using the rate of six Mcf of +natural gas (including natural gas liquids) to one Bbl of crude oil or +condensate. +PRODUCTION -- At December 31, 2002, we held a working interest in 305 +productive wells, of which 147 were considered oil and 158 were considered +natural gas. A productive well is a well producing oil or natural gas in +commercial quantities. A working interest is the operating interest under an oil +or natural gas lease. It gives the owner the right to explore for and produce +oil or natural gas from the lease. We were the operator of 256 of these wells at +December 31, 2002. The following table sets forth our net oil and natural gas +production, average sales price, and average production costs associated with +our production during the periods indicated: +YEAR ENDED DECEMBER 31, +------------------------ +2002 2001 2000 +------ ------ ------ +Average net daily production: +Oil (Bbls)............................................... 794 739 752 +Gas (Mcf)................................................ 5,109 4,654 3,784 +Total (BOE).............................................. 1,646 1,515 1,383 +Average sales prices: +Oil (per Bbl)............................................ $25.02 $24.88 $29.99 +Gas (per Mcf)............................................ 2.91 4.12 3.87 +Average production costs (per BOE)......................... $ 4.22 $ 5.32 $ 6.41 +CUSTOMERS +The customers of each of our four business segments are operators or +purchasers of oil and natural gas. Our customer base includes both major and +independent oil and natural gas companies. During 2002, no single customer +accounted for 10% or more of our consolidated operating revenues. +COMPETITION +CONTRACT DRILLING AND PRESSURE PUMPING BUSINESSES -- Our land drilling and +pressure pumping businesses are intensely competitive due to the fact that the +supply of available land drilling rigs and pressure pumping equipment exceeds +the demand for those rigs and 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. +7 +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 addition, some of our +competitors have greater financial resources than we do which may enable them +to: +- better withstand industry downturns, +- compete more effectively on the basis of price, and +- acquire existing rigs or equipment or build new rigs or 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. +DRILLING AND COMPLETION FLUIDS BUSINESS -- The drilling and completion +fluids services industry is highly competitive. Price is generally the most +important competitive factor in the industry. Other competitive factors include +the availability of chemicals and experienced personnel, the reputation of the +fluids services provider in the drilling industry, and our relationship with +existing customers. Some of our competitors have substantially greater resources +and longer operating histories than we have. We believe that competition for +drilling and completion fluids service contracts will continue to be intense. +OIL AND NATURAL GAS BUSINESS -- There is substantial competition for the +acquisition of oil and natural gas leases suitable for development and +exploration and for the hiring of experienced personnel. Our competitors in this +business include: +- major integrated oil and natural gas companies, +- independent oil and natural gas companies, +- drilling and production purchase programs, and +- individual operators. +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 financial resources, staffs, and +facilities greater than ours. +GOVERNMENT AND ENVIRONMENTAL REGULATION +All of our operations and facilities are subject to numerous federal, +state, foreign, and local laws, rules, and regulations related to various +aspects of our business, including: +- drilling of oil and natural gas wells, +- containment and disposal of hazardous materials, oilfield waste, other +waste materials, and acids, +- use of underground storage tanks, and +- use of underground injection wells. +To date, we have not been required to expend significant resources in order +to satisfy applicable environmental laws and regulations. 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 for +noncompliance. +Our business is generally affected by political developments and by +federal, state, foreign, and local laws and regulations, which relate to the oil +and natural gas industry. The adoption of laws and regulations affecting the oil +and natural gas industry for economic, environmental, and other policy reasons +could increase costs relating to drilling and production. They could have an +adverse effect on our operations. Several state and federal environmental laws +and regulations currently apply to our operations and may become more stringent +in the future. +8 +We have utilized operating and disposal practices that were or are +currently 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 operated by us or our predecessors. In addition, some of these +properties have been operated by third parties over whom we have no control +either as to such entities' treatment of hydrocarbon and other materials or the +manner in which such materials may have been disposed of or released. +The federal Comprehensive Environmental Response Compensation and Liability +Act of 1980, 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 and comparable state +statutes govern the disposal of "hazardous wastes." Although CERCLA currently +excludes petroleum from the definition of "hazardous substances," and the +Resource Conservation and Recovery Act also excludes certain classes of +exploration and production wastes from regulation, such exemptions by Congress +under both CERCLA and the Resource Conservation and Recovery Act may be deleted, +limited, or modified in the future. If such changes are made to CERCLA and/or +the Resource Conservation and Recovery Act, 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 +and implementing regulations govern: +- the prevention of discharges, including oil and produced water spills, +and +- liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than previous oil +pollution liability and prevention laws. It imposes strict liability for a +comprehensive and expansive list of damages from an oil spill into waters from +facilities. Liability may be imposed for oil removal costs and a variety of +public and private damages. Penalties may also be imposed for violation of +federal safety, construction, and operating regulations, and for failure to +report a spill or to cooperate fully in a clean-up. +The Oil Pollution Act also expands the authority and capability of the +federal government to direct and manage oil spill clean-up and operations, and +requires operators to prepare oil spill response plans in cases where it can +reasonably be expected that substantial harm will be done to the environment by +discharges on or into navigable waters. We have spill prevention control and +countermeasure plans in place for our oil and natural gas properties in each of +the areas in which we operate and for each of the stockpoints operated by our +drilling and completion fluids business. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a +responsible party, such as Patterson-UTI, 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 and various state +and local laws impose certain air quality requirements on Patterson-UTI. +Amendments to the Clean Air Act revised the definition of "major source" such +that emissions from both wellhead and associated equipment involved in oil and +natural gas production may be added to determine if a source is a "major +source." As a consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting process may +require capital expenditures in order to comply with permit limits. +9 +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, +- fires, and +- explosions. +These hazards could cause: +- personal injury or death, +- suspension of drilling operations, or +- serious damage or destruction of the equipment involved and, in addition +to environmental damage, could cause substantial damage to producing +formations and surrounding areas. +Damage to the environment, including property contamination in the form of +either soil or ground water contamination, could also result from our +operations, particularly through: +- oil or produced water spillage, +- natural gas leaks, and +- fires. +In addition, we could become subject to liability for reservoir damages. +The occurrence of a significant event, including pollution or environmental +damages, could materially affect our operations and financial condition. +As a protection against operating hazards, we maintain insurance coverage +we believe to be adequate, including: +- all-risk physical damages, +- employer's liability, +- commercial general liability, and +- workers compensation insurance. +We believe that we are adequately insured for public liability and property +damage to others with respect to our operations. However, such insurance may not +be sufficient to protect us against liability for all consequences of: +- personal injury, +- well disasters, +- extensive fire damage, +- damage to the environment, or +- other hazards. +We also carry insurance coverage for major physical damage to our drilling +rigs. However, we do not carry insurance against loss of earnings resulting from +such damage. In view of the difficulties that may be encountered in renewing +such insurance at reasonable rates, no assurance can be given that: +- we will be able to maintain the type and amount of coverage that we +believe to be adequate at reasonable rates, or +- any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain of the risks. These indemnity +agreements typically require our customers to hold us harmless in the +10 +event of loss of production or reservoir damage. These contractual +indemnifications may not be supported by adequate insurance maintained by the +customer. +EMPLOYEES +We employed approximately 4,607 full-time persons (268 office personnel and +4,339 field personnel) at December 31, 2002. The number of field employees +fluctuates depending on the current and expected demand for our services. We +consider our employee relations to be satisfactory. None of our employees are +represented by a union. +SEASONALITY +Seasonality does not significantly affect our overall operations. However, +our pressure pumping division in Appalachia and our drilling operations in +Canada are subject to slow periods of activity during the spring thaw. In +addition, our drilling operations in Canada are subject to slow periods of +activity during the fall. +RAW MATERIALS AND SUBCONTRACTORS +Patterson-UTI uses many suppliers of raw materials and services. These +materials and services have been and continue to be available. We also utilize +numerous independent subcontractors from various trades. +INCORPORATION BY REFERENCE +The various factors disclosed under the caption "Forward Looking Statements +and Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the +Private Securities Litigation Reform Act of 1995," beginning on page 13 of this +Report, are incorporated by this reference into Items 1 and 2 of this Report. +Readers of this Report should review those factors in conjunction with their +review of Items 1 and 2. +CORPORATE HEADQUARTERS, FIELD OFFICES, AND OTHER FACILITIES +Our corporate headquarters are located in Snyder, Texas. We also have a +number of offices, yard, 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 (915) 574-6300. There are a +number of improvements at our headquarters, including: +- an office building with approximately 34,000 square feet of office space +and storage, +- a shop facility with approximately 7,000 square feet used for drilling +equipment repairs and metal fabrication, +- a truck shop facility with approximately 10,000 square feet used to +maintain, overhaul and repair our truck fleet, +- an engine shop facility with approximately 20,000 square feet used to +overhaul and repair the engines used to power our drilling rigs, and +- an open-ended metal storage facility with approximately 10,200 square +feet. +We have regional administrative offices, yard, and stockpoint facilities in +many of the areas in which we operate. The facilities are primarily used to +support the day-to-day operations, including the repair and maintenance of +equipment as well as the storage of equipment, inventory, and supplies and to +facilitate administrative responsibilities and sales. +CONTRACT DRILLING OPERATIONS -- Our drilling services are supported by +several administrative offices and yard facilities located throughout our areas +of operations including: +- Texas, +- New Mexico, +11 +- Oklahoma, +- Utah, and +- Western Canada. +DRILLING AND COMPLETION FLUIDS -- Our drilling and completion fluids +services are supported by several administrative offices and stockpoint +facilities located throughout our areas of operations including: +- Texas, +- Louisiana, +- New Mexico, and +- Oklahoma. +PRESSURE PUMPING -- Our pressure pumping services are supported by several +offices and yard facilities located throughout our areas of operations +including: +- Pennsylvania, +- Ohio, +- West Virginia, +- Kentucky, and +- New York. +OIL AND NATURAL GAS -- Our oil and natural gas services are supported by +administrative and field offices in Texas. +We own our headquarters in Snyder and lease the majority of our other +facilities. We do not believe that any of these other facilities are +individually material to our operations. We believe that our existing facilities +are suitable and adequate to meet our needs. +ITEM 3. LEGAL PROCEEDINGS. +Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc. +("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson +Petroleum LP, and Patterson-UTI Drilling Company LP, in the Circuit Court, +Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter +agreement entered into in July 2000 between Patterson Petroleum LP and Westfort +concerning the drilling of a daywork well in Mississippi. This lawsuit was filed +by Westfort after Patterson Petroleum LP made demand on Westfort for payment of +the contract drilling services. +In this lawsuit, Westfort alleges breach of contract, fraud, and negligence +causes of action. Westfort seeks alleged monetary damages, the return of shares +of Westfort stock, unspecified damages from alleged lost profits, lost use of +income stream, and additional operating expenses, along with alleged punitive +damages to be determined by the jury, but not less than 25% of Patterson's net +worth. The Company intends to vigorously contest the allegations made by +Westfort and asserts claims against Westfort, including the monies owed +Patterson Petroleum LP under the letter agreement in the amount of approximately +$5,075,000. +In addition to the Westfort lawsuit, we are party to various legal +proceedings arising in the normal course of our business. We do not believe that +the outcome of these proceedings, either individually or in the aggregate, will +have a material adverse effect on our financial condition. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. +None. +12 +FORWARD LOOKING STATEMENTS AND CAUTIONARY +STATEMENTS FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS +OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 +Patterson-UTI from time to time makes written or oral forward-looking +statements, including statements contained in this Annual Report on Form 10-K, +our other filings with the SEC, press releases, and reports to stockholders. +These forward-looking statements are made pursuant to the "safe harbor" +provisions of the Private Securities Litigation Reform Act of 1995. These +statements include, without limitation, statements relating to liquidity, +financing of operations, sources and sufficiency of funds, and impact of +inflation. The words "believes," "budgeted," "expects," "project," "will," +"could," "may," "plans," "intends," "strategy," or "anticipates," and similar +expressions are used to identify our forward-looking statements. We do not +undertake to update, revise, or correct any of our forward-looking information. +We include the following cautionary statement in accordance with the "safe +harbor" provisions of the Private Securities Litigation Reform Act of 1995 for +any forward-looking statement made by us, or on our behalf. The factors +identified in this cautionary statement are important factors (but not +necessarily all of the important factors) that could cause actual results to +differ materially from those expressed in any forward-looking statement made by +us, or on our behalf. Where any such forward-looking statement includes a +statement of the assumptions or bases underlying such forward-looking statement, +we caution that, while we believe such assumptions or bases to be reasonable and +make them in good faith, assumed facts or bases almost always vary from actual +results. The differences between assumed facts or bases and actual results can +be material, depending upon the circumstances. +Where, in any forward-looking statement, Patterson-UTI, or our management, +expresses an expectation or belief as to the future results, such expectation or +belief is expressed in good faith and believed to have a reasonable basis. +However, there can be no assurance that the statement of expectation or belief +will result, or be achieved or accomplished. Taking this into account, the +following are identified as important risk factors currently applicable to, or +which could readily be applicable to, Patterson-UTI: +PATTERSON-UTI IS DEPENDENT ON THE OIL AND NATURAL GAS INDUSTRY AND MARKET +PRICES FOR OIL AND NATURAL GAS. DECLINES IN OIL AND NATURAL GAS PRICES HAVE +ADVERSELY AFFECTED OUR OPERATIONS. +Our revenue, profitability, and rate of growth are substantially dependent +upon prevailing prices for oil and natural gas. In recent years, oil and natural +gas prices and, therefore, the level of drilling, exploration, development, and +production, have been extremely volatile. Prices are affected by: +- market supply and demand, +- international military, political, and economic conditions, and +- the ability of the Organization of Petroleum Exporting Countries, +commonly known as OPEC, to set and maintain production and price targets. +All of these factors are beyond our control. Natural gas prices fell from +an average of $4.41 per Mcf in the second quarter of 2001 to an average of $3.41 +per Mcf for the same period in 2002. During this same period, the average number +of the Company's rigs operating dropped by approximately 50%. The average market +price of natural gas improved to $4.31 in the fourth quarter of 2002 resulting +in marginal improvement in the average number of rigs operating. We expect oil +and natural gas prices to continue to be volatile and to affect our financial +condition and operations and ability to access sources of capital. +A GENERAL EXCESS OF OPERABLE LAND DRILLING RIGS ADVERSELY AFFECTS OUR PROFIT +MARGINS PARTICULARLY IN TIMES OF WEAKER DEMAND. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 and from mid-1999 through the second +quarter of 2001. However, except for those periods and other occasional upturns, +generally, there have been substantially more drilling rigs available than +necessary to meet +13 +demand in most operational and geographic segments of the North American land +drilling industry. As a result, drilling contractors have had difficulty +sustaining profit margins. +In addition to adverse effects that future declines in demand could have on +Patterson-UTI, ongoing factors which could adversely affect utilization rates +and pricing, even in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +- movement of drilling rigs from region to region, +- reactivation of land-based drilling rigs, or +- new construction of drilling rigs. +We cannot predict either the future level of demand for our contract +drilling services or future conditions in the oil and natural gas contract +drilling business. +SHORTAGES OF DRILL PIPE, REPLACEMENT PARTS, AND OTHER RELATED RIG EQUIPMENT +ADVERSELY AFFECTS PATTERSON-UTI'S OPERATING RESULTS. +During periods of increased demand for drilling services, the industry has +experienced shortages of drill pipe, replacement parts, and other related rig +equipment. These shortages can cause the price of these items to increase +significantly and require that orders for the items be placed well in advance of +expected use. These price increases and delays in delivery may require us to +substantially increase capital expenditures in our contract drilling segment. +Severe shortages could impair our ability to operate our drilling rigs. +THE VARIOUS BUSINESS SEGMENTS IN WHICH WE OPERATE ARE HIGHLY COMPETITIVE WITH +EXCESS CAPACITY WHICH MAY ADVERSELY AFFECT OUR OPERATING RESULTS. +Our land drilling and pressure pumping businesses are intensely competitive +due to the fact that the supply of available land drilling rigs and pressure +pumping equipment exceeds the demand for those rigs and 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. +Patterson-UTI believes 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 addition, some of our +competitors have greater financial resources than we do which may enable them +to: +- better withstand industry downturns, +- compete more effectively on the basis of price, and +- acquire existing rigs or equipment or build new rigs or equipment. +In recent years, many drilling and pressure pumping companies have +consolidated or merged with other companies. Although this consolidation has +decreased the total number of competitors, we believe the competition for +drilling and pressure pumping services will continue to be intense. +The drilling and completion fluids services industry is highly competitive. +Price is generally the most important competitive factor in the industry. Other +competitive factors include the availability of chemicals and experienced +personnel, the reputation of the fluids services provider in the drilling +industry, and our relationship with existing customers. Some of our competitors +have substantially greater resources and longer operating histories than we +have. We believe that competition for our drilling and completion fluids service +contracts will continue to be intense. +LABOR SHORTAGES ADVERSELY AFFECT OUR OPERATING RESULTS. +During periods of increased demand for contract drilling services, the +industry experiences shortages of qualified drilling rig personnel. During these +periods, our ability to attract and retain sufficient qualified personnel to +market and operate our drilling rigs is adversely affected which in turn has a +negative impact on +14 +both our operations and profitability. Operationally, it is more difficult to +hire qualified personnel which adversely affects our ability to mobilize +inactive rigs in response to the increased demand for our contract drilling +services. Additionally, wage rates for drilling personnel are likely to +increase, resulting in greater operating costs and reduced operating margins. +During the last upturn in our industry, we experienced an approximate 30% to 40% +increase in wage rates to our drilling personnel which reduced operating +margins. +CONTINUED GROWTH OF PATTERSON-UTI THROUGH RIG ACQUISITION IS NOT ASSURED. +We have increased our drilling rig fleet over the past several years +through mergers and acquisitions. The land drilling industry has experienced +significant consolidation over the past several years, and there can be no +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 would: +- have sufficient capital resources to complete additional acquisitions, +- successfully integrate acquired operations and assets, +- be able to manage effectively the growth and increased size, +- be successful in deploying idle or stacked rigs, +- be able to maintain the crews and market share attributable to operating +drilling rigs acquired, or +- be successful in improving our financial condition, results of operation, +business, or prospects in any material manner as a result of any +completed acquisition. +We may incur substantial indebtedness to finance future acquisitions and +also may issue equity securities or convertible securities in connection with +any such acquisitions. Debt service requirements could represent a significant +burden on our results of operations and financial condition and the issuance of +additional equity could be dilutive to our existing stockholders. Also, +continued growth could strain our management, operations, employees, and +resources. +THE NATURE OF OUR BUSINESS OPERATIONS PRESENTS INHERENT RISKS OF LOSS THAT, IF +NOT INSURED OR INDEMNIFIED AGAINST, COULD ADVERSELY AFFECT PATTERSON-UTI'S +OPERATING RESULTS. +Our operations are subject to many hazards inherent in the contract +drilling, pressure pumping, and drilling and completion fluids businesses, which +in turn could cause personal injury or death, work stoppage, or serious damage +to our equipment. Our operations could also cause environmental and reservoir +damages. We maintain insurance coverage and have indemnification agreements with +many of our customers. However, there is no assurance that such insurance or +indemnification agreements would adequately protect Patterson-UTI against +liability or losses from all consequences of the hazards. Additionally, there +can be no assurance that insurance would be available to cover any or all of +these risks, or, even if available, that insurance premiums or other costs would +not rise significantly in the future, so as to make such insurance prohibitive. +We have elected in some cases to accept a greater amount of risk through +increased deductibles on certain insurance policies. For example, we maintain a +$750,000 per occurrence deductible on our workers' compensation insurance +coverage and a $1 million per occurrence deductible on our general liability +insurance coverage. These levels of self-insurance expose us to increased +operating costs and risks. +VIOLATIONS OF ENVIRONMENTAL LAWS AND REGULATIONS COULD MATERIALLY ADVERSELY +AFFECT PATTERSON-UTI 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 to +Patterson-UTI of compliance with these laws and regulations could be +substantial. Failure to comply with these requirements could subject +Patterson-UTI to substantial civil and criminal penalties. In addition, federal +law imposes a variety of regulations on "responsible parties" related to +15 +the prevention of oil spills and liability for damages from such spills. +Patterson-UTI, as an owner and operator of land-based drilling rigs may be +deemed to be a responsible party under federal law. Our operations and +facilities are subject to numerous state and federal environmental laws, rules, +and regulations, including, without limitation, laws concerning the containment, +and disposal of hazardous substances, oil field waste and other waste materials, +the use of underground storage tanks and the use of underground injection wells. +SOME OF OUR CONTRACT DRILLING SERVICES ARE DONE UNDER TURNKEY AND FOOTAGE +CONTRACTS, WHICH ARE FINANCIALLY RISKY. +A portion of our contract drilling is done under turnkey and footage +contracts, which involve significant risks. Under turnkey drilling contracts, we +contract to drill a well to a certain depth under specified conditions for a +fixed price. Under footage contracts, we contract to drill a well to a certain +depth under specified conditions at a fixed price per foot. The risk to us under +these types of drilling contracts are greater than on a well drilled on a +daywork basis. Unlike daywork contracts, we must bear the cost of performing +drilling services until the target depth is reached. We must also make +significant up-front working capital commitments prior to receiving payment. In +addition, we must assume most of the risk associated with the drilling +operations, generally assumed by the operator of the well on a daywork contract, +including blowouts, loss of hole from fire, machinery breakdowns, and abnormal +drilling conditions. Accordingly, if severe drilling problems are encountered in +drilling wells under such contracts, we could suffer substantial losses. +ANTI-TAKEOVER MEASURES IN OUR CHARTER DOCUMENTS AND UNDER STATE LAW COULD +DISCOURAGE AN ACQUISITION OF PATTERSON-UTI AND THEREBY AFFECT THE RELATED +PURCHASE PRICE. +Patterson-UTI, as a Delaware corporation, is 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 of Patterson-UTI +may find it more difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our securities of +certain opportunities to sell or otherwise dispose of the securities at +above-market prices pursuant to any such transactions. +WE HAVE PAID NO DIVIDENDS ON OUR COMMON STOCK AND HAVE NO PLANS TO PAY +DIVIDENDS. +We have not declared or paid cash dividends on our common shares in the +past. We do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. The terms of our existing credit facility limit +payment of dividends without the prior written consent of the lenders. +16 +PART II +ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. +Our common stock, par value $0.01 per share is publicly traded on the +Nasdaq National Market and is quoted under the symbol "PTEN." In December 2002, +our common stock was added to the Nasdaq-100 Index and in November 2001, our +common stock was added to the S&P MidCap 400 Index. Our common stock is also +included in several other market indexes. +The following table sets forth the high and low closing prices of our +common shares for the periods indicated: +HIGH LOW +------ ------ +2002: +First quarter............................................... $29.74 $19.09 +Second quarter.............................................. 34.12 27.61 +Third quarter............................................... 29.60 20.92 +Fourth quarter.............................................. 33.88 24.42 +2001: +First quarter............................................... $40.44 $29.94 +Second quarter.............................................. 36.28 17.87 +Third quarter............................................... 18.68 11.69 +Fourth quarter.............................................. 24.48 12.16 +As of December 31, 2002, there were approximately 300 holders of record and +approximately 17,000 beneficial holders of our common shares. +We have not declared or paid cash dividends on our common shares in the +past and do not expect to declare or pay any cash dividends on our common stock +in the foreseeable future. Instead, we intend to retain our earnings to support +the operations and growth of our business. Any future cash dividends would +depend on future earnings, capital requirements, financial condition, and other +factors deemed relevant by the board of directors. In addition, the terms of our +existing credit facility limit payment of dividends without the prior written +consent of the lenders. +The following table summarizes as of December 31, 2002, certain information +regarding equity compensation to our employees, officers, directors, and other +persons under our equity compensation plans: +EQUITY COMPENSATION PLAN INFORMATION +-------------------------------------------------------- +NUMBER OF +NUMBER OF SECURITIES +SECURITIES TO WEIGHTED- REMAINING AVAILABLE +BE ISSUED UPON AVERAGE EXERCISE FOR FUTURE ISSUANCE +EXERCISE OF PRICE OF UNDER EQUITY +OUTSTANDING OUTSTANDING COMPENSATION PLANS +OPTIONS, OPTIONS, (EXCLUDING +WARRANTS AND WARRANTS AND SECURITIES REFLECTED +PLAN CATEGORY RIGHTS RIGHTS IN COLUMN (A)) +------------- -------------- ---------------- -------------------- +(A) (B) (C) +Equity compensation plans approved by +security holders....................... 5,157,364 $17.31 877,536 +Equity compensation plans not approved by +security holders(1).................... 981,524 $19.15 8,733 +--------- ------ ------- +Total............................... 6,138,888 $17.61 886,269 +========= ====== ======= +--------------- +(1) The Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan was approved by +the Company's Board of Directors in July 2001. The terms of the Plan provide +for grants of stock options to eligible employees +17 +other than officers and directors of the Company. The total number of stock +options that could be granted under the Plan was 1,000,000. No Incentive +Stock Options may be awarded under the Plan. All options are granted with an +exercise price equal to or greater than the fair market value of the +Company's common stock at the time of grant. The vesting schedule and term +are set by the Compensation Committee of the Board of Directors. +Also in July 2001, the Company's Board of Directors approved option grants, +not included in any of the Company's stock option plans, for two +non-employee directors, each covering options to purchase 12,000 shares of +the Company's common stock at an exercise price greater than the fair +market value of the Company's common stock on the grant date. The options +vested in November 2001 and expire in November 2005. +ITEM 6. SELECTED FINANCIAL DATA. +The selected consolidated financial data of Patterson-UTI as of December +31, 2002, 2001, 2000, 1999, and 1998, and for each of the five years then ended +should be read in conjunction with "Management's Discussion and Analysis of +Financial Condition and Results of Operations" and the Consolidated Financial +Statements and related Notes thereto, included as Items 7 and 8, respectively, +of this document. Historical financial statements as presented herein, have been +restated to provide for the retroactive effect of the merger with UTI Energy +Corp., on May 8, 2001. +YEAR ENDED DECEMBER 31, +---------------------------------------------------- +2002 2001 2000 1999 1998 +-------- -------- -------- -------- -------- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +INCOME STATEMENT DATA: +Operating revenues: +Drilling.............................. $410,295 $839,931 $512,998 $266,212 $329,003 +Drilling and completion fluids........ 69,943 94,456 32,053 11,686 13,397 +Pressure pumping...................... 32,996 39,600 21,465 20,721 23,365 +Oil and natural gas................... 14,723 15,988 15,806 8,563 7,170 +Other................................. -- -- -- 184 192 +-------- -------- -------- -------- -------- +Total.............................. 527,957 989,975 582,322 307,366 373,127 +-------- -------- -------- -------- -------- +Operating costs and expenses: +Drilling.............................. 318,201 487,343 384,840 224,590 253,768 +Drilling and completion fluids........ 60,762 80,034 26,545 9,864 10,205 +Pressure pumping...................... 19,802 21,146 13,403 12,219 14,041 +Oil and natural gas................... 3,956 5,190 4,872 2,500 3,696 +Depreciation, depletion, and +amortization....................... 91,216 86,159 61,464 52,553 51,436 +General and administrative............ 26,140 28,561 22,190 17,735 20,004 +Bad debt expense...................... 320 2,045 570 282 1,233 +Merger costs.......................... -- 5,943 -- -- -- +Restructuring and other charges....... 4,700 7,202 -- -- -- +Other................................. (538) (820) (147) (2,927) (335) +-------- -------- -------- -------- -------- +Total.............................. 524,559 722,803 513,737 316,816 354,048 +-------- -------- -------- -------- -------- +Operating income (loss)................. 3,398 267,172 68,585 (9,450) 19,079 +-------- -------- -------- -------- -------- +Other income (expense).................. 441 (677) (8,481) (7,053) (5,953) +-------- -------- -------- -------- -------- +Income (loss) before income taxes....... 3,839 266,495 60,104 (16,503) 13,126 +Income tax expense (benefit)............ 1,670 102,333 22,878 (4,766) 5,328 +-------- -------- -------- -------- -------- +18 +YEAR ENDED DECEMBER 31, +---------------------------------------------------- +2002 2001 2000 1999 1998 +-------- -------- -------- -------- -------- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +Net income (loss)....................... $ 2,169 $164,162 $ 37,226 $(11,737) $ 7,798 +======== ======== ======== ======== ======== +Net income (loss) per common share: +Basic................................. $ 0.03 $ 2.15 $ 0.52 $ (0.18) $ 0.12 +======== ======== ======== ======== ======== +Diluted............................... $ 0.03 $ 2.07 $ 0.50 $ (0.18) $ 0.12 +======== ======== ======== ======== ======== +Weighted average number of common shares +outstanding: +Basic................................. 78,705 76,407 71,207 66,483 63,785 +======== ======== ======== ======== ======== +Diluted............................... 81,252 79,197 74,841 66,483 65,757 +======== ======== ======== ======== ======== +BALANCE SHEET DATA: +Current assets.......................... $243,015 $199,458 $237,742 $106,091 $ 94,708 +Total assets............................ 942,509 869,642 739,898 496,715 468,554 +Current liabilities..................... 75,152 89,286 110,443 60,930 46,871 +Long-term debt.......................... -- -- 79,416 82,196 87,435 +Stockholders' equity.................... 737,556 687,142 481,299 309,695 300,881 +Working capital......................... 167,863 110,172 127,299 45,161 47,837 +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. +Commitments and Contingencies -- We have no commitments or contingencies +which would require further disclosure in our financial statements other than +letters of credit totaling $25.5 million at December 31, 2002, maintained for +the benefit of various insurance companies as collateral for retrospective +premiums and retained losses which would become payable under the terms of the +underlying insurance contracts. No amounts have been drawn under the letters of +credit. +Net income for the year ended December 31, 2002 includes a charge of $4.7 +million related to the financial failure in 2002 of a workers' compensation +insurance carrier that had provided coverage for the Company in prior years. +Trading and investing -- We have not engaged in trading activities that +include high-risk securities, such as derivatives and non-exchange traded +contracts. We invest cash primarily in highly liquid, short-term investments +such as overnight deposits, money markets, and highly rated municipal and +commercial bonds. However in June 2002 and October 2002, we acquired a total of +1,058,673 shares of common stock of TMBR/Sharp Drilling, Inc., a company whose +stock is traded on the NASDAQ National Market System, for a total of $17.7 +million. +Description of business -- We are a leading provider of land-based contract +drilling services to major and independent oil and natural gas operators in +Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Utah, and Western Canada. +As of December 31, 2002, we owned 324 drilling rigs. We provide drilling fluids, +completion fluids, and related services to oil and natural gas operators in West +Texas, Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast +regions of Texas and Louisiana, and the Gulf of Mexico. Drilling and completion +fluids are used by oil and natural gas operators during the drilling process to +control pressure when drilling oil and natural gas wells. We provide pressure +pumping services to oil and natural gas operators 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 are also engaged +in the development, +19 +exploration, acquisition, and production of oil and natural gas. Our oil and +natural gas operations are focused in producing regions in West Texas, Southeast +New Mexico, and South Texas. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 and from mid-1999 through the second +quarter of 2001. However, except for those periods and other occasional upturns, +generally, there have been substantially more drilling rigs available than +necessary to meet demand in most operational and geographic segments of the +North American land drilling industry. As a result, drilling contractors have +had difficulty sustaining profit margins. +In addition to adverse effects that future declines in demand could have on +Patterson-UTI, ongoing factors which could adversely affect utilization rates +and pricing, even in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +- movement of drilling rigs from region to region, +- reactivation of land-based drilling rigs, or +- new construction of drilling rigs. +We cannot predict either the future level of demand for our contract +drilling services or future conditions in the oil and natural gas contract +drilling business. +CRITICAL ACCOUNTING POLICIES +In addition to established accounting policies, our consolidated financial +statements are impacted by certain estimates and assumptions made by management. +The following is a discussion of our critical accounting policies pertaining to +property and equipment, oil and natural gas properties, impairment, revenue +recognition, and the use of estimates. +Property and equipment -- Property and equipment, including betterments +which extend the useful life of the asset, are stated at cost. Maintenance and +repairs are charged to expense when incurred. We provide for the depreciation of +our property and equipment using the straight-line method over the estimated +useful lives. No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our assets, including +intangible 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. Provisions for asset impairment are charged to income when +estimated future cash flows, on an undiscounted basis, are less than the asset's +net book value. Impairment charges are recorded based on discounted cash flows. +There were no impairment charges during the years 2002, 2001 or 2000. +Oil and natural gas properties -- We follow the successful efforts method +of accounting, using the field as the accumulation center, for our oil and +natural gas properties. Exploration and development costs which result directly +in the discovery of oil and natural gas reserves are capitalized. Exploration +costs which do not result directly in the discovery of oil and natural gas +reserves are charged to expense. Capitalized costs, consisting of lease and well +equipment, lease acquisition costs, and intangible development costs, are +depreciated, depleted, and amortized on the units-of-production method, based on +petroleum engineer estimates of recoverable oil and natural gas reserves of each +respective field. Impairment of proved oil and natural gas properties is +periodically assessed based on estimated future net cash flows at a field level +as determined by an independent reserve engineer. Impairment expense is included +in depreciation, depletion, and amortization in the accompanying financial +statements. +Revenue recognition -- Generally, revenues are recognized when services are +performed. The Company follows the percentage-of-completion method of accounting +for footage contract drilling arrangements. Under this method, drilling revenues +and costs related to a well in progress are recognized proportionately over the +time it takes to drill the well. Due to the nature of turnkey contract drilling +arrangements and risks therein, the Company follows the completed contract +method of accounting for such arrangements. Under this method, all drilling +advances and costs (including maintenance and repairs) related to a well in +progress are deferred and +20 +recognized as revenues and expenses in the period the well is completed. +Provisions for losses on incomplete or in-process wells are made when estimated +total costs are expected to exceed estimated total revenues. +Use of estimates -- The preparation of financial statements in conformity +with generally accepted accounting principles requires management to make +certain estimates and assumptions. These estimates and assumptions affect the +reported amounts of assets and liabilities, the disclosures of contingent assets +and liabilities at the balance sheet date and the amounts of revenues and +expenses recognized during the reporting period. Actual results could differ +from such estimates. +Key estimates used by management include: +- allowance for doubtful accounts, +- depreciation, depletion, and amortization, +- asset impairment, +- reserves for self-insured levels of insurance coverages, and +- fair values of assets and liabilities assumed. +For additional information on our accounting policies, see Note 1 of Notes +to Consolidated Financial Statements included as a part of Item 8 of this +Report. +Related party transactions -- In 2001 and 2000, we leased a 1981 Beech +King-Air 90 airplane owned by SSI Oil and Gas, Inc., an entity beneficially +owned 50% by Cloyce A. Talbott, Patterson-UTI's Chief Executive Officer, and +directly owned 50% by A. Glenn Patterson, Patterson-UTI's President/Chief +Operating Officer. Under the terms of the lease, we paid a monthly rental of +$9,200, the costs of fuel, insurance, taxes, and maintenance of the aircraft. +Such amounts totaled approximately $212,000 and $194,000 for 2001 and 2000, +respectively. +The Company operates certain oil and natural gas properties in which +certain of our affiliated persons have participated, either individually or +through entities they control, in the prospects or properties in which we have +an interest. These participations, which have been on a working interest basis, +have been in prospects or properties originated or acquired by Patterson-UTI. At +December 31, 2002, affiliated persons were working interest owners in 215 of the +256 wells then being operated by Patterson-UTI. Sales of working interests are +made by Patterson-UTI to reduce its economic risk in the properties. Generally, +it is more efficient for Patterson-UTI to sell the working interests to these +affiliated persons than to market them to unrelated third parties. Sales were +made by Patterson-UTI at its cost, comprised of Patterson-UTI's costs of +acquiring and preparing the working interests for sale. These costs were paid by +the working interest owners on a pro rata basis based upon their working +interest ownership percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests were sold to +unaffiliated persons. +21 +The following table sets forth production revenues received and joint +interest billings paid by each of the affiliated persons during 2002 for all +wells operated by Patterson-UTI in which they have working interests. These +numbers do not necessarily represent their profits or losses from these +interests because the joint interest billings do not include the parties' +related drilling and leasehold acquisition costs incurred prior to January 1, +2002. +YEAR ENDED DECEMBER 31, +2002 +--------------------------- +PRODUCTION JOINT +REVENUES INTEREST +NAME RECEIVED (1) BILLINGS (2) +---- ------------ ------------ +Cloyce A. Talbott........................................... $ 178,277 $ 81,371 +Anita Talbott (3)........................................... 91,268 52,359 +Jana Talbott, Executrix to the Estate of Steve Talbott +(3)....................................................... 11,471 6,097 +Stan Talbott (3)............................................ 25,922 14,084 +John Evan Talbott Trust (3)................................. 2,298 1,024 +Lisa Beck and Stacy Talbott (3)............................. 542,625 185,207 +SSI Oil & Gas, Inc. (4)..................................... 271,808 182,538 +IDC Enterprises, Ltd. (5)................................... 5,559,548 4,751,785 +SSSL, Ltd. (6) (8).......................................... -- 13,380 +---------- ---------- +Subtotal.................................................. 6,683,217 5,287,845 +---------- ---------- +A. Glenn Patterson.......................................... 127,160 47,246 +Glenn Patterson Family Limited Partnership (7) (8).......... -- 13,365 +Robert Patterson (7)........................................ 8,893 2,684 +Thomas M. Patterson (7)..................................... 8,893 2,684 +---------- ---------- +Subtotal.................................................. 144,946 65,979 +---------- ---------- +Jonathan D. Nelson.......................................... 60,571 151,649 +Steve DeGroat............................................... 16,390 5,440 +---------- ---------- +Subtotal.................................................. 76,961 157,089 +---------- ---------- +Total.................................................. $6,905,124 $5,510,913 +========== ========== +--------------- +(1) Revenues received 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 billings have been paid on a timely basis. +(3) Anita Talbott is the wife of Cloyce A. Talbott. Stan Talbott, Lisa Beck, and +Stacy Talbott are Mr. Talbott's adult children. Steve Talbott is the +deceased son of Mr. Talbott. John Evan Talbott is Mr. Talbott's grandson. +(4) SSI Oil & Gas, Inc. is beneficially owned 50% by Cloyce A. Talbott and +directly owned 50% by A. Glenn Patterson. +(5) IDC Enterprises, Ltd. is 50% owned by Cloyce A. Talbott and 50% owned by A. +Glenn Patterson. +(6) SSSL, Ltd. is a limited partnership in which children and grandchildren of +Mr. Talbott are beneficiaries and Mr. Talbott is the general partner. +(7) Robert and Thomas M. Patterson are A. Glenn Patterson's adult children. The +Glenn Patterson Family Limited Partnership is a partnership in which each of +Mr. Patterson's children shares equally and Mr. Patterson is the manager. +(8) Revenues included in IDC Enterprises, Ltd. revenues. +22 +In 2002 and 2001, we paid approximately $279,000 and $387,000, +respectively, to TMP Truck and Trailer LP ("TMP"), an entity owned by Thomas M. +Patterson (son of A. Glenn Patterson), for certain equipment and metal +fabrication services. Purchases from TMP were at then current market prices. +LIQUIDITY AND CAPITAL RESOURCES +As of December 31, 2002, we had working capital of approximately $167.9 +million including cash and cash equivalents of approximately $82.2 million. For +2002, our significant sources of cash flow were: +- $131.4 million derived from operations, +- $15.7 million from the exercise of stock options and warrants, and +- $1.8 million from the sale of certain property and equipment. +Correspondingly, we used approximately $17.7 million to acquire 1,058,673 +common shares of TMBR/Sharp Drilling, Inc. (see Note 6 of Notes to Consolidated +Financial Statements included as part of Item 8 to this Report), and +approximately $83.8 million: +- to make capital expenditures for the betterment and refurbishment of our +drilling rigs, +- for the acquisition and procurement of drilling equipment, +- to fund capital expenditures for our drilling and completion fluids and +pressure pumping divisions, and +- to fund leasehold acquisition and development and exploration of oil and +natural gas properties. +On March 21, 2002, we acquired five SCR electric land-based drilling rigs +from Odin Drilling, Inc., increasing our land-based drilling fleet to 324. The +purchase price of $16.9 million consisted of 650,000 shares of our common stock +valued at $26.06 per share. A deferred tax liability of $4.1 million was +recorded as a result of the transaction. The transaction was accounted for as a +purchase and the related purchase price was allocated among the rigs based on +their estimated fair values. +Subsequent to December 31, 2002, the Company purchased seven drilling rigs, +in two separate transactions, for an aggregate purchase price of $16.5 million +in cash. The acquisitions were funded out of the Company's existing cash. +We believe that the current level of cash and short-term investments, +together with cash generated from operations, should be sufficient to meet our +capital needs. From time to time, acquisition opportunities are reviewed +relating to our business. The timing, size or success of any acquisition and the +associated capital commitments are unpredictable. Over the longer term, should +further opportunities for growth requiring capital arise, we believe we would be +able to satisfy these needs through a combination of working capital, cash +generated from operations, and either debt or equity financing. However, there +can be no assurance that such capital would be available. +23 +RESULTS OF OPERATIONS +COMPARISON OF THE YEARS ENDED DECEMBER 31, 2002 AND 2001 +The following tables summarize operations by business segment for the +twelve months ended December 31, 2002 and 2001: +YEAR ENDED DECEMBER 31, +------------------------------ +CONTRACT DRILLING 2002 2001 % CHANGE +----------------- -------- -------- -------- +(DOLLARS IN 000'S) +Revenues.............................................. $410,295 $839,931 (51.2)% +Direct operating costs................................ $318,201 $487,343 (34.7)% +Selling, general, and administrative.................. $ 3,987 $ 5,277 (24.4)% +Depreciation and amortization......................... $ 80,500 $ 72,797 10.6% +Operating income...................................... $ 7,607 $274,514 (97.2)% +Operating days........................................ 45,919 76,871 (40.3)% +Average revenue per operating day..................... $ 8.94 $ 10.93 (18.2)% +Average direct operating cost per operating day....... $ 6.93 $ 6.34 9.3% +Average margin per operating day...................... $ 2.01 $ 4.59 (56.2)% +Number of owned rigs at end of period................. 324 319 1.6% +Average number of rigs owned during period............ 323 302 7.0% +Average rigs operating................................ 126 211 (40.3)% +Rig utilization percentage............................ 39% 70% (44.3)% +Capital expenditures.................................. $ 64,821 $150,788 (57.0)% +The following table illustrates the average market price of natural gas and +our average rigs operating for each of the fiscal quarters in 2002 and 2001: +1ST 2ND 3RD 4TH +QUARTER QUARTER QUARTER QUARTER +------- ------- ------- ------- +2002: +Average natural gas price........................... $2.51 $3.41 $3.20 $4.31 +Average rigs operating.............................. 117 119 127 140 +2001: +Average natural gas price........................... $6.23 $4.41 $2.78 $2.70 +Average rigs operating.............................. 231 248 225 140 +Our rig count began to decline in the third quarter of 2001 and continued +until March 2002 when our rig count bottomed at 103 rigs (90 rigs in the U.S. +and 13 rigs in Canada). The deterioration in our rig count was primarily the +result of weakening natural gas prices through mid-February 2002. Natural gas +prices then rebounded somewhat and our rig count improved marginally during the +period from March through September 2002. In the fourth quarter of 2002, +consistent with improved natural gas prices, our rig count continued to improve +and averaged 140 rigs (132 rigs in the U.S. and 8 rigs in Canada). +The decreased operating results in 2002 were reflective of a significant +decline in demand for our contract drilling services as evidenced by decreases +in the number of operating days and average rig utilization. Increased +competition during 2002 for available jobs resulted in downward pricing pressure +and decreased operating revenues. Increased operating costs were primarily +attributable to increased labor costs, including payroll expenses and workers' +compensation insurance costs. Payroll expenses increased as experienced field +personnel were retained despite the significant decline in our average rig +utilization. Management believes this strategy is beneficial as it (1) retains +experienced personnel and (2) facilitates the Company's response to increased +demand levels as industry conditions improve. General and administrative +expenses decreased primarily as a result of reduced incentive compensation in +2002. Depreciation and amortization increased in +24 +2002 primarily as a result of (1) significant capital expenditures in 2001 and +2002 to maintain, modify, and refurbish our drilling fleet and (2) our +acquisition of drilling rigs and related equipment from Cleere Drilling Company +in December 2001. +YEAR ENDED DECEMBER 31, +---------------------------- +DRILLING AND COMPLETION FLUIDS 2002 2001 % CHANGE +------------------------------ ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $69,943 $94,456 (26.0)% +Direct operating costs.................................. $60,762 $80,034 (24.1)% +Selling, general, and administrative.................... $ 7,243 $ 7,936 (8.7)% +Depreciation and amortization........................... $ 2,216 $ 2,644 (16.2)% +Operating income (loss)................................. $ (278) $ 3,842 (107.2)% +Total jobs.............................................. 1,457 1,920 (24.1)% +Average revenue per job................................. $ 48.00 $ 49.20 (2.4)% +Average costs per job................................... $ 41.70 $ 41.68 (1.1)% +Average margin per job.................................. $ 6.30 $ 7.52 (9.8)% +Capital expenditures.................................... $ 1,571 $ 4,937 (68.2)% +The decrease in revenues for our drilling and completion fluids operations +were primarily attributable to industry conditions, as discussed in Contract +Drilling above, and the resulting 24.1% decline in the number of jobs completed. +Operating expenses per job increased despite reduced activity levels due to a +portion of the segment's operating expenses being fixed in nature. The 8.7% +decrease in selling, general, and administrative expense is primarily the result +of reduced employee incentive compensation in 2002. +YEAR ENDED DECEMBER 31, +---------------------------- +PRESSURE PUMPING 2002 2001 % CHANGE +---------------- ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $32,996 $39,600 (16.7)% +Direct operating costs.................................. $19,802 $21,146 (6.4)% +Selling, general, and administrative.................... $ 4,301 $ 3,910 10.0% +Depreciation............................................ $ 2,803 $ 1,895 47.9% +Operating income........................................ $ 6,090 $12,649 (51.9)% +Total jobs.............................................. 3,796 4,609 (17.6)% +Average revenue per job................................. $ 8.69 $ 8.59 1.2% +Average costs per job................................... $ 5.22 $ 4.59 13.7% +Average margin per job.................................. $ 3.47 $ 4.00 (13.3)% +Capital expenditures.................................... $ 7,399 $ 7,756 (4.6)% +The decreases in revenues and expenses for our pressure pumping operations +were primarily attributable to industry conditions, as discussed in Contract +Drilling above. Expansion of our pressure pumping services in 2001 and 2002 into +the Appalachian regions of Kentucky and West Virginia resulted in increased +depreciation and selling, general, and administrative expenses in 2002. The +increase in average revenue per job was attributable to the change in the +composition of operating revenues. Cementing revenue as a percent of total +operating revenue increased from 34.2% in 2001 to 55.6% in 2002 and fracturing +revenue as a percent of total operating revenue decreased from 46.7% in 2001 to +39.6% in 2002. Cementing jobs, as compared to fracturing jobs, typically +generate greater revenues as the services being provided are much more +extensive, requiring us to incur increased operating and material costs. +Additionally, operating costs per job increased in 2002 since a portion of +direct operating costs remain constant despite fluctuating activity levels. +25 +YEAR ENDED DECEMBER 31, +OIL AND NATURAL GAS PRODUCTION AND ---------------------------- +EXPLORATION 2002 2001 % CHANGE +---------------------------------- ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $14,723 $15,988 (7.9)% +Direct operating costs.................................. $ 3,956 $ 5,190 (23.8)% +Selling, general, and administrative.................... $ 1,571 $ 1,537 2.2% +Depreciation and depletion.............................. $ 5,251 $ 8,505 (38.3)% +Operating income........................................ $ 3,945 $ 756 421.8% +Capital expenditures.................................... $ 6,357 $ 7,956 (28.3)% +Average net daily oil production (Bbls)................. 794 739 7.4% +Average net daily gas production (Mcf).................. 5,109 4,654 9.8% +Average oil sales price (per Bbl)....................... $ 25.02 $ 24.88 0.6% +Average gas sales price (per Mcf)....................... $ 2.91 $ 4.12 (29.4)% +Decreased revenues are attributable to lower average prices received from +sales of natural gas. Direct operating costs declined in 2002 primarily due to +the divestiture of marginally productive wells in 2002, thus reducing lease +operating costs. Depreciation and depletion declined in 2002 primarily due to +significant decreased depletion expense in 2002 as a result of increased +commodity prices at December 31, 2002. +YEAR ENDED DECEMBER 31, +-------------------------- +CORPORATE AND OTHER 2002 2001 % CHANGE +------------------- ------ ------ -------- +(DOLLARS IN 000'S) +Selling, general, and administrative...................... $9,038 $9,901 (8.7)% +Bad debt expense.......................................... $ 320 $2,045 (84.4)% +Depreciation and amortization............................. $ 446 $ 318 40.3% +Other income.............................................. $ (538) $ (820) 34.4% +Merger costs.............................................. $ -- $5,943 (100.0)% +Restructuring and other charges........................... $4,700 $7,202 (34.7)% +Capital expenditures...................................... $3,695 $5,320 (30.5)% +The decrease in selling, general, and administrative expense of 8.7% +primarily relates to reduced employee incentive compensation in 2002. +Restructuring and other charges reflect a $4.7 million charge taken in the +second quarter of 2002 due to the financial failure of a workers' compensation +insurance carrier we used from 1992 until March 2001. Merger costs, +restructuring, and other charges in 2001 include costs related to the merger +with UTI. +26 +COMPARISON OF THE YEARS ENDED DECEMBER 31, 2001 AND 2000 +The following tables summarize operations by business segment for the +twelve months ended December 31, 2001 and 2000: +YEAR ENDED DECEMBER 31, +------------------------------ +CONTRACT DRILLING 2001 2000 % CHANGE +----------------- -------- -------- -------- +(DOLLARS IN 000'S) +Revenues.............................................. $839,931 $512,998 63.7% +Direct operating costs................................ $487,343 $384,840 26.6% +Selling, general, and administrative.................. $ 5,277 $ 5,457 (3.3)% +Depreciation and amortization......................... $ 72,797 $ 54,274 34.1% +Operating income...................................... $274,514 $ 68,427 301.2% +Operating days........................................ 76,871 63,303 21.4% +Average revenue per operating day..................... $ 10.93 $ 8.10 34.9% +Average direct operating cost per operating day....... $ 6.34 $ 6.08 4.3% +Average margin per operating day...................... $ 4.59 $ 2.02 127.2% +Number of owned rigs at end of period................. 319 275 16.0% +Average number of rigs owned during period............ 302 263 14.8% +Average rigs operating................................ 211 173 22.0% +Rig utilization percentage............................ 70% 66% 6.1% +Capital expenditures.................................. $150,788 $116,836 29.1% +The significant increases shown were reflective of increased activity in +the contract drilling industry and specifically: +- increases in average rig utilization and in the number of operating days, +- increases in dayrates as evidenced by average revenue per operating day, +and +- the addition of an average 39 drilling rigs from 2000 to 2001. +Largely due to favorable commodity prices during the first half of 2001, +the demand for our contract drilling services was strong as we reached our peak +rig utilization of 81% in July. However, beginning in the third quarter of 2001 +the industry conditions began to deteriorate as the commodity prices of oil and +natural gas significantly weakened. Market prices for oil fell from +approximately $27 per barrel at the end of 2000 to approximately $17 per barrel +in late 2001 and natural gas prices declined from approximately $10 per Mcf to +under $3 per Mcf for the same time period. Accordingly, the demand for our +contract drilling services was negatively impacted. +YEAR ENDED DECEMBER 31, +---------------------------- +DRILLING AND COMPLETION FLUIDS 2001 2000 % CHANGE +------------------------------ ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $94,456 $32,053 194.7% +Direct operating costs.................................. $80,034 $26,545 201.5% +Selling, general, and administrative.................... $ 7,936 $ 4,294 84.8% +Depreciation and amortization........................... $ 2,644 $ 1,464 80.6% +Operating income (loss)................................. $ 3,842 $ (250) N/A% +Total jobs.............................................. 1,920 601 219.5% +Average revenue per job................................. $ 49.20 $ 53.33 (7.7)% +Average costs per job................................... $ 41.68 $ 44.17 (5.6)% +Average margin per job.................................. $ 7.52 $ 9.16 (17.9)% +Capital expenditures.................................... $ 4,937 $10,166 (51.4)% +27 +The increases above were primarily attributable to the purchase of the +fluids division of Ambar, Inc., during October 2000 providing for twelve months +of activity in 2001 versus three months in 2000. Deteriorating industry +conditions as noted above also had an adverse impact on our drilling and +completion fluids division beginning in the third quarter of 2001. +YEAR ENDED DECEMBER 31, +---------------------------- +PRESSURE PUMPING 2001 2000 % CHANGE +---------------- ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $39,600 $21,465 84.5% +Direct operating costs.................................. $21,146 $13,403 57.8% +Selling, general, and administrative.................... $ 3,910 $ 3,196 22.3% +Depreciation............................................ $ 1,895 $ 1,564 21.2% +Operating income........................................ $12,649 $ 3,302 283.1% +Total jobs.............................................. 4,609 3,329 38.5% +Average revenue per job................................. $ 8.59 $ 6.45 33.2% +Average costs per job................................... $ 4.59 $ 4.03 13.9% +Average margin per job.................................. $ 4.00 $ 2.42 65.3% +Capital expenditures.................................... $ 7,756 $ 4,426 75.2% +The improvement in the pressure pumping segment's operating results were +primarily attributable to improved market conditions throughout 2001 as +evidenced by the increase in number of jobs and revenue per job. +YEAR ENDED DECEMBER 31, +---------------------------- +OIL AND NATURAL GAS PRODUCTION AND EXPLORATION 2001 2000 % CHANGE +---------------------------------------------- ------- ------- -------- +(DOLLARS IN 000'S) +Revenues................................................ $15,988 $15,806 1.2% +Direct operating costs.................................. $ 5,190 $ 4,872 6.5% +Selling, general, and administrative.................... $ 1,537 $ 1,453 5.8% +Depreciation and depletion.............................. $ 8,505 $ 3,674 131.5% +Operating income........................................ $ 756 $ 5,807 (87.0)% +Capital expenditures.................................... $ 7,956 $ 5,341 49.0% +Average net daily oil production (Bbls)................. 739 752 (1.7)% +Average net daily gas production (Mcf).................. 4,654 3,784 23.0% +Average oil sales price (per Bbl)....................... $ 24.88 $ 29.99 (17.0)% +Average gas sales price (per Mcf)....................... $ 4.12 $ 3.87 6.5% +Increased revenues are attributable to increased production and sales of +natural gas. Direct operating costs increased in 2001 primarily due to the +increased levels of production of natural gas. Depreciation and depletion +increased in 2001 due to increased depletion expense in 2001 as a result of +significantly decreased commodity prices at December 31, 2001 and impairment +expense in 2001 of $1.1 million compared to no impairment expense in 2000. This +impairment in 2001 was attributable to declining commodity prices and +unfavorable results from certain oil and natural gas prospects. +28 +YEAR ENDED DECEMBER 31, +-------------------------- +CORPORATE AND OTHER 2001 2000 % CHANGE +------------------- ------ ------ -------- +(DOLLARS IN 000'S) +Selling, general, and administrative...................... $9,901 $7,790 27.1% +Bad debt expense.......................................... $2,045 $ 570 258.8% +Depreciation and amortization............................. $ 318 $ 488 (35.0)% +Other income.............................................. $ (820) $ (147) (457.8)% +Merger costs.............................................. $5,943 $ -- 100.0% +Restructuring and other charges........................... $7,202 $ -- 100.0% +Capital expenditures...................................... $5,320 $ -- 100.0% +The merger costs and restructuring charges incurred in 2001 are associated +with our merger with UTI that occurred in 2001. Selling, general, and +administrative expenses increased primarily as a result of the increased +activity as evidenced by the operating segments' individual results of +operations and the growth of our Company in 2001 through acquisitions. Included +in this increase are management and operational bonuses resulting from improved +operations. +INCOME TAXES +YEAR ENDED DECEMBER 31, +--------------------------- +2002 2001 2000 +------ -------- ------- +(DOLLARS IN 000'S) +Income before income tax................................ $3,839 $266,495 $60,104 +Income tax expense...................................... 1,670 102,333 22,878 +Effective tax rate...................................... 43.5% 38.4% 38.1% +Patterson-UTI's remaining unutilized investment tax credit carryforward +expired in 2000. Net operating losses were fully utilized in 2001 and our +remaining alternative minimum tax credit of $602,000 may be carried forward +indefinitely. Other deferred tax assets consist primarily of various allowance +accounts and tax deferred expenses expected to generate a future tax benefit of +approximately $12.9 million. +Our effective income tax rate for 2002 includes 38% applicable to our +statutory Federal and state income tax rates and approximately 6% attributable +to permanent differences. The significance of the impact of the permanent +differences to our effective income tax rate in 2002 was largely attributable to +our reduced 2002 pretax earnings. +We record non-cash deferred Federal income taxes based primarily on the +relationship between the amount of our unused Federal NOL carryforwards and the +temporary differences between the book basis and tax basis in our assets. +Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the year in which those temporary +differences are expected to be settled. As a result of fully recognizing the +benefit of our deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We incurred deferred income tax expense of +approximately $23.5 million, $14.6 million, and $15.9 million for 2002, 2001, +and 2000, respectively. +VOLATILITY OF OIL AND NATURAL GAS PRICES +Our revenue, profitability, and future rate of growth are substantially +dependent upon prevailing prices for oil and natural gas, with respect to all of +our operating segments. Historically, oil and natural gas prices and markets +have been volatile. Prices are affected by market supply and demand factors as +well as actions of state and local agencies, the United States and foreign +governments, and international cartels. All of these are beyond our control. Any +significant or extended decline in oil and/or natural gas prices would have a +material adverse effect on our financial condition and results of operations. +The contract drilling business experienced increased demand for drilling +services from 1995 through most of 1997 and from mid-1999 and continued through +the second quarter of 2001. However, except for those +29 +periods and other occasional upturns, generally, there have been substantially +more drilling rigs available than necessary to meet demand in most operational +and geographic segments of the North American land drilling industry. As a +result, drilling contractors have had difficulty sustaining profit margins. +IMPACT OF INFLATION +We believe that inflation will not have a significant near-term impact on +our financial position. +RECENTLY-ISSUED ACCOUNTING STANDARDS +The Financial Accounting Standards Board ("FASB") issued Statement of +Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," +("SFAS No. 142") in June 2001. SFAS No. 142 supersedes APB Opinion No. 17, +"Intangible Assets." Under the provisions of SFAS No. 142, which the Company +adopted on January 1, 2002, goodwill is no longer amortized but is subject to an +annual impairment test. During the years ended December 31, 2001 and 2000, +goodwill amortization totaled approximately $4.7 million each year. +The FASB issued Statement of Financial Accounting Standards No. 143, +"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001. +SFAS No. 143 addresses financial accounting requirements for retirement +obligations associated with tangible long-lived assets. The provisions of SFAS +No. 143, which the Company adopted on January 1, 2003, will result in the +Company recording a liability of approximately $1.1 million for estimated costs +to be incurred in connection with the abandonment of oil and natural gas +properties in the future. In addition, the cumulative effect of this change in +accounting policy, which will be recorded in the consolidated statement of +income in the first quarter of 2003, will total approximately $500,000, net of +tax. +The FASB issued Statement of Financial Accounting Standards No. 144, +"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No. +144") in August 2001. SFAS No. 144 supersedes SFAS No. 121 and APB Opinion No. +30. The provisions of SFAS No. 144, which the Company adopted on January 1, +2002, did not have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 145, +"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement +No. 13, and Technical Corrections," ("SFAS No. 145") in April 2002. SFAS No. 145 +amends existing authoritative pronouncements to make various technical +corrections, clarify meanings, or describe their applicability under changed +conditions. The provisions of SFAS No. 145, which the Company adopted in 2002, +did not have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 146, +"Accounting for Costs Associated with Exit or Disposal Activities," ("SFAS No. +146") in June 2002. SFAS No. 146 is effective for exit or disposal activities +that are initiated after December 31, 2002. The provisions of SFAS No. 146 are +not expected to have a material impact on the Company's consolidated financial +statements. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +We currently have no exposure to interest rate market risk as we have no +outstanding balance under our credit facility. Should we incur a balance in the +future, we would have exposure associated with the floating rate of the interest +charged on that balance. The revolving credit facility calls for periodic +interest payments at a floating rate ranging from LIBOR plus 1.75% to 2.75%. The +applicable rate above LIBOR (1.75% at December 31, 2002) is based upon our +trailing twelve-month EBITDA (earnings before interest expense, income taxes, +and depreciation, depletion and amortization expense). Our exposure to interest +rate risk due to changes in LIBOR is not expected to be material. +We conduct some business in Canadian dollars through our Canadian +land-based drilling operations. The exchange rate between Canadian dollars and +U.S. dollars has fluctuated over the last ten years. If the value of the +Canadian dollar against the U.S. dollar weakens, revenues and earnings of our +Canadian operations will be +30 +reduced when they are translated to U.S. dollars. Also, the value of our +Canadian net assets in U.S. dollars may decline. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +Financial Statements are filed as a part of this Report at the end of Part +IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and +are incorporated herein by this reference. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE. +None. +31 +PART III +The information required by Part III is omitted from this Report because +Patterson-UTI will file a definitive proxy statement pursuant to Regulation 14A +of the Securities Exchange Act of 1934 no later than 120 days after the end of +the fiscal year covered by this document and certain information included +therein is incorporated herein by reference. +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 11. EXECUTIVE COMPENSATION. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. +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. +32 +PART IV +ITEM 14. CONTROLS AND PROCEDURES. +Within 90 days before filing this Report, we evaluated the effectiveness of +the design and operation of our disclosure controls and procedures. Our +disclosure controls and procedures are the controls and other procedures that we +designed to ensure that we record, process, summarize, and report in a timely +manner the information we must disclose in reports that we file with the SEC. +Our disclosure controls and procedures include our internal accounting controls. +Based on our evaluation, our disclosure controls and procedures were effective. +There were no significant changes in our internal controls or in other +factors that could significantly affect these controls subsequent to the date of +our evaluation. +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on page F-1 of this Report. +(a)(2) Financial Statement Schedule +Schedule II -- Valuation and qualifying accounts is filed herewith on page +S-1. +All other financial statement schedules have been omitted because they are +not applicable or the information required therein is included elsewhere in the +financial statements or notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by reference +herein. +2.1 Agreement and Plan of Merger dated March 10, 2002 among +Patterson-UTI Energy, Inc., Patterson-UTI Drilling Company +LP, LLLP and Odin Drilling, Inc.(1) +2.2 Stock Purchase Agreement dated as of June 11, 2002 by and +among Patterson-UTI Energy, Inc. and Roper Family +Properties, Ltd., Estate of Joe G. Roper, Patricia R. +Elledge, Judy Kathleen Roper Davis, Jeanie Elisabeth +Cornelius and J. Mark Roper.(2) +2.3 Stock Purchase Agreement dated as of October 28, 2002 by and +between Patterson-UTI Energy, Inc. and J. Mark Roper.(3) +3.1 Restated Certificate of Incorporation.(4) +3.1.1 Certificate of Correction of Restated Certificate of +Incorporation.(5) +3.2 Amended and Restated Bylaws.(5) +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(6) +3.3.1 Amendment to Rights Agreement dated as of October 23, +2001.(7) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson-UTI Energy, Inc. regarding authorized Common Stock +and Preferred Stock.(8) +4.2 Certificate of Designation.(9) +4.2.1 Amendment to Certificate of Designation.(5) +4.3 Registration Rights Agreement with Bear, Stearns and Co. +Inc., dated March 25, 1994, as assigned by REMY Capital +Partners III, L.P.(5) +4.4 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as +amended.(10)* +4.5 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended.(11)* +4.6 Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan.(12)* +4.7 Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc.(13)* +4.8 Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan.(13)* +4.9 1997 Stock Option Plan of DSI Industries, Inc.(12)* +33 +4.10 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.).(5)* +4.11 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Stephen J. DeGroat (a +non-employee director of Patterson-UTI Energy, Inc.).(5)* +10.1 For additional material contracts, see Exhibits 4.3 through +4.11. +10.2 Amended and Restated Loan and Security Agreement, dated July +26, 2002.(8) +10.3 Revolving Loan Promissory Note, dated July 26, 2002.(8) +10.4 Amended and Restated Guaranty Agreement, dated July 26, +2002.(8) +10.5 Amended and Restated Pledge Agreement, dated July 26, +2002.(8) +10.6 Model Form Operating Agreement.(14) +10.7 Form of Drilling Bid Proposal and Footage Drilling +Contract.(14) +10.8 Form of Turnkey Drilling Agreement.(14) +21.1 Subsidiaries of the Registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Auditors -- Ernst & Young LLP. +23.3 Consent of Independent Petroleum Engineer -- M. Brian +Wallace, P.E. +99.1 Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as Adopted pursuant +to Section 906 of the Sarbanes-Oxley Act of 2002. +--------------- +(1) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended March 31, 2002. +(2) Incorporated herein by reference to Item 7, "Material to be Filed as +Exhibits" to Amendment No. 1 to Schedule 13D filed on October 31, 2002. +(3) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2002. +(4) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated and filed on May 8, 2001. +(5) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the +fiscal year ended December 31, 2001. +(6) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on Form 8-A filed on January 14, 1997. +(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed +on October 31, 2001. +(8) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on +August 1, 2001. +(9) Incorporated herein by reference to Item 2, "Exhibits" to Registration +Statement on Form 8-A (File No. 000-22664) filed on January 14, 1997. +(10) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on March 13, 1998. +(11) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on November 4, 1997. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470) +filed on July 25, 2001. +(13) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No.1 to Registration Statement on Form S-8 (file No. 333-60466) +filed on July 25, 2001. +(14) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993. +* Management Contract or Compensatory Plan identified as required by Item +15(a)(3) of Form 10-K. +(b) Reports on Form 8-K. +There were no reports on Form 8-K filed during the three months ended +December 31, 2002. +34 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +PAGE +------- +Report of Independent Accountants; PricewaterhouseCoopers +LLP....................................................... F-2 +Report of Independent Auditors; Ernst & Young LLP........... F-3 +Consolidated Financial Statements: +Consolidated Balance Sheets as of December 31, 2002 and +2001................................................... F-4 +Consolidated Statements of Income for the years ended +December 31, 2002, 2001, and 2000...................... F-5 +Consolidated Statements of Changes In Stockholders' Equity +for the years ended +December 31, 2002, 2001, and 2000...................... F-6 +Consolidated Statements of Changes In Cash Flows for the +years ended +December 31, 2002, 2001, and 2000...................... F-7 +Notes to Consolidated Financial Statements................ F-9 +F-1 +REPORT OF INDEPENDENT ACCOUNTANTS +The Board of Directors and Stockholders of +Patterson-UTI Energy, Inc. +In our opinion, based on our audits and the report of other auditors, the +consolidated financial statements listed in the accompanying index present +fairly, in all material respects, the financial position of Patterson-UTI +Energy, Inc. and its subsidiaries at December 31, 2002 and 2001, and the results +of their operations and their cash flows for each of the three years in the +period ended December 31, 2002 in conformity with accounting principles +generally accepted in the United States of America. In addition, in our opinion, +based on our audits and the report of other auditors, the financial schedule +listed in Item 14(a) (2) presents fairly, in all material respects, the +information set forth therein, when read in conjunction with the related +consolidated financial statements. These financial statements and financial +schedule are the responsibility of the Company's management; our responsibility +is to express an opinion on these financial statements and financial schedule +based on our audits. The consolidated financial statements give retroactive +effect to the merger of UTI Energy Corp. ("UTI") on May 8, 2001 in a transaction +accounted for as a pooling of interests, as described in Note 2 to the +consolidated financial statements. We did not audit the financial statements of +UTI, which statements reflect total assets of $330 million as of December 31, +2000 and total revenues of $275 million for the year ended December 31, 2000. +Those statements were audited by other auditors whose report thereon has been +furnished to us, and our opinion expressed herein, insofar as it relates to the +amounts included for UTI, is based solely on the report of the other auditors. +We conducted our audits of these statements in accordance with auditing +standards generally accepted in the United States of America, which require that +we plan and perform the audit to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes +examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements, assessing the accounting principles used and +significant estimates made by management, and evaluating the overall financial +statement presentation. We believe that our audits and the report of other +auditors provide a reasonable basis for our opinion. +As discussed in Notes 1 and 5 to the consolidated financial statements, in +accordance with Statement of Financial Accounting Standards No. 142, "Goodwill +and Other Intangible Assets," beginning in 2002 the Company no longer amortizes +goodwill. +PricewaterhouseCoopers LLP +Houston, Texas +February 3, 2003 +F-2 +REPORT OF INDEPENDENT AUDITORS +To the Board of Directors +Patterson-UTI Energy, Inc. +We have audited the consolidated balance sheet of UTI Energy Corp. as of +December 31, 2000 and the related consolidated statements of operations, changes +in shareholders' equity and cash flows for the year then ended (not presented +separately herein). Our audit also included the financial statement schedule +listed in the Index at Item 14(a) of UTI Energy Corp.'s Annual Report (Form +10-K) for the year ended December 31, 2000 (also not presented separately +herein). These financial statements and schedule are the responsibility of the +Company's management. Our responsibility is to express an opinion on these +financial statements and schedule based on our audit. +We conducted our audit in accordance with auditing standards generally +accepted in the United States. Those standards require that we plan and perform +the audit to obtain reasonable assurance about whether the financial statements +are free of material misstatement. An audit also includes assessing the +accounting principles used and significant estimates made by management, as well +as evaluating the overall financial statement presentation. We believe that our +audit provides a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above +present fairly, in all material respects, the consolidated financial position of +UTI Energy Corp. at December 31, 2000, and the consolidated results of its +operations and its cash flows for the year then ended, in conformity with +accounting principles generally accepted in the United States. Also, in our +opinion, the related financial statement schedule, when considered in relation +to the basic financial statements taken as a whole, presents fairly in all +material respects the information set forth therein. +Ernst & Young LLP +Houston, Texas +February 16, 2001 +F-3 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(IN THOUSANDS, EXCEPT SHARE DATA) +DECEMBER 31, +------------------- +2002 2001 +-------- -------- +ASSETS +Current assets: +Cash and cash equivalents................................. $ 82,154 $ 33,584 +Accounts receivable, net of allowance for doubtful +accounts of $3,144 and $4,021 at December 31, 2002 and +2001, respectively..................................... 99,014 133,837 +Federal and state income taxes receivable, net............ 24,719 1,673 +Inventory................................................. 15,323 16,272 +Deferred tax assets....................................... 15,290 8,747 +Other..................................................... 6,515 5,345 +-------- -------- +Total current assets.............................. 243,015 199,458 +Property and equipment, at cost, net........................ 627,734 614,420 +Goodwill and other intangible assets, net................... 51,313 51,634 +Investment in equity securities............................. 17,707 -- +Other....................................................... 2,740 4,130 +-------- -------- +Total assets...................................... $942,509 $869,642 +======== ======== +LIABILITIES AND STOCKHOLDERS' EQUITY +Current liabilities: +Accounts payable: +Trade.................................................. $ 30,618 $ 43,873 +Accrued revenue distributions.......................... 6,266 4,072 +Other.................................................. 2,755 4,833 +Accrued expenses.......................................... 35,513 36,508 +-------- -------- +Total current liabilities......................... 75,152 89,286 +Deferred tax liabilities.................................... 127,006 92,859 +Other....................................................... 2,795 355 +-------- -------- +Total liabilities................................. 204,953 182,500 +-------- -------- +Commitments and contingencies............................... -- -- +Stockholders' equity: +Preferred stock, par value $.01; authorized 1,000,000 +shares, no shares issued............................... -- -- +Common stock, par value $.01; authorized 200,000,000 +shares with 81,576,674 and 78,462,543 issued and +80,070,126 and 76,955,995 outstanding at December 31, +2002 and 2001, respectively............................ 816 784 +Additional paid-in capital................................ 489,201 441,475 +Retained earnings......................................... 261,003 258,834 +Accumulated other comprehensive loss...................... (1,809) (2,296) +Treasury stock, at cost, 1,506,548 shares................. (11,655) (11,655) +-------- -------- +Total stockholders' equity........................ 737,556 687,142 +-------- -------- +Total liabilities and stockholders' equity...... $942,509 $869,642 +======== ======== +The accompanying notes are an integral part of these consolidated financial +statements. +F-4 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(IN THOUSANDS, EXCEPT PER SHARE DATA) +YEARS ENDED DECEMBER 31, +------------------------------ +2002 2001 2000 +-------- -------- -------- +Operating revenues: +Drilling.................................................. $410,295 $839,931 $512,998 +Drilling and completion fluids............................ 69,943 94,456 32,053 +Pressure pumping.......................................... 32,996 39,600 21,465 +Oil and natural gas....................................... 14,723 15,988 15,806 +-------- -------- -------- +527,957 989,975 582,322 +-------- -------- -------- +Operating costs and expenses: +Drilling.................................................. 318,201 487,343 384,840 +Drilling and completion fluids............................ 60,762 80,034 26,545 +Pressure pumping.......................................... 19,802 21,146 13,403 +Oil and natural gas....................................... 3,956 5,190 4,872 +Depreciation, depletion, and amortization................. 91,216 86,159 61,464 +General and administrative................................ 26,140 28,561 22,190 +Bad debt expense.......................................... 320 2,045 570 +Merger costs.............................................. -- 5,943 -- +Restructuring and other charges........................... 4,700 7,202 -- +Other..................................................... (538) (820) (147) +-------- -------- -------- +524,559 722,803 513,737 +-------- -------- -------- +Operating income............................................ 3,398 267,172 68,585 +-------- -------- -------- +Other income (expense): +Interest income........................................... 1,110 2,080 1,377 +Interest expense.......................................... (532) (3,142) (10,108) +Other..................................................... (137) 385 250 +-------- -------- -------- +441 (677) (8,481) +-------- -------- -------- +Income before income taxes.................................. 3,839 266,495 60,104 +-------- -------- -------- +Income tax expense (benefit): +Current................................................... (21,878) 87,773 6,931 +Deferred.................................................. 23,548 14,560 15,947 +-------- -------- -------- +1,670 102,333 22,878 +-------- -------- -------- +Net income.................................................. $ 2,169 $164,162 $ 37,226 +======== ======== ======== +Net income per common share: +Basic..................................................... $ 0.03 $ 2.15 $ 0.52 +======== ======== ======== +Diluted................................................... $ 0.03 $ 2.07 $ 0.50 +======== ======== ======== +Weighted average number of common shares outstanding: +Basic..................................................... 78,705 76,407 71,207 +======== ======== ======== +Diluted................................................... 81,252 79,197 74,841 +======== ======== ======== +The accompanying notes are an integral part of these consolidated financial +statements. +F-5 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY +(IN THOUSANDS) +COMMON STOCK ACCUMULATED +------------------ ADDITIONAL OTHER +NUMBER PAID-IN RETAINED COMPREHENSIVE TREASURY +OF SHARES AMOUNT CAPITAL EARNINGS INCOME (LOSS) STOCK TOTAL +--------- ------ ---------- -------- ------------- -------- -------- +December 31, 1999.................. 69,542 $695 $261,559 $57,446 $ -- $(10,005) $309,695 +Issuance of common stock......... 4,203 42 120,964 -- -- -- 121,006 +Issuance of stock purchase +warrant........................ -- -- 900 -- -- -- 900 +Treasury stock acquired.......... -- -- -- -- -- (1,650) (1,650) +Exercise of stock purchase +warrants....................... 1,054 11 683 -- -- -- 694 +Exercise of stock options........ 1,451 15 6,254 -- -- -- 6,269 +Tax benefit related to exercise +of stock options............... -- -- 7,129 -- -- -- 7,129 +Foreign currency translation..... -- -- -- -- 30 -- 30 +Net income....................... -- -- -- 37,226 -- -- 37,226 +------ ---- -------- -------- ------- -------- -------- +December 31, 2000.................. 76,250 763 397,489 94,672 30 (11,655) 481,299 +Issuance of common stock......... 1,260 12 31,405 -- -- -- 31,417 +Issuance of stock purchase +warrant........................ -- -- 2,600 -- -- -- 2,600 +Exercise of stock purchase +warrants....................... 121 1 1,819 -- -- -- 1,820 +Exercise of stock options........ 832 8 4,237 -- -- -- 4,245 +Tax benefit related to exercise +of stock options............... -- -- 3,925 -- -- -- 3,925 +Foreign currency translation..... -- -- -- -- (2,326) -- (2,326) +Net income....................... -- -- -- 164,162 -- -- 164,162 +------ ---- -------- -------- ------- -------- -------- +December 31, 2001.................. 78,463 784 441,475 258,834 (2,296) (11,655) 687,142 +Issuance of common stock......... 650 7 16,933 -- -- -- 16,940 +Exercise of stock options and +warrants....................... 2,464 25 15,714 -- -- -- 15,739 +Tax benefit related to exercise +of stock options............... -- -- 15,079 -- -- -- 15,079 +Foreign currency translation..... -- -- -- -- 457 -- 457 +Change in unrealized gain on +securities, net of tax......... -- -- -- -- 30 -- 30 +Net income....................... -- -- -- 2,169 -- -- 2,169 +------ ---- -------- -------- ------- -------- -------- +December 31, 2002.................. 81,577 $816 $489,201 $261,003 $(1,809) $(11,655) $737,556 +====== ==== ======== ======== ======= ======== ======== +The accompanying notes are an integral part of these consolidated financial +statements. +F-6 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS +(IN THOUSANDS) +YEARS ENDED DECEMBER 31, +-------------------------------- +2002 2001 2000 +-------- --------- --------- +Cash flows from operating activities: +Net income............................................... $ 2,169 $ 164,162 $ 37,226 +Adjustments to reconcile net income to net cash provided +by operating activities: +Depreciation, depletion, and amortization................ 91,216 86,159 61,464 +Provision for bad debts.................................. 320 2,045 570 +Deferred income tax expense.............................. 23,548 14,560 15,947 +Tax benefit related to exercise of stock options......... 15,079 3,925 7,129 +Other.................................................... (538) (648) 881 +Changes in operating assets and liabilities: +Accounts receivable................................. 34,565 6,648 (63,323) +Inventory and other current assets.................. (222) (355) 7,105 +Accrued federal income taxes receivable............. (23,216) 796 2,596 +Accounts payable.................................... (11,079) (33,174) 24,077 +Other liabilities................................... (409) 9,888 4,525 +-------- --------- --------- +Net cash provided by operating activities........ 131,433 254,006 98,197 +-------- --------- --------- +Cash flows from investing activities: +Acquisitions............................................. -- (40,546) (56,627) +Purchases of property and equipment...................... (83,843) (172,850) (95,822) +Proceeds from sales of property and equipment............ 1,813 742 3,528 +Purchase of investment equity securities................. (17,659) -- -- +Change in other assets................................... 1,097 (1,101) 630 +-------- --------- --------- +Net cash used in investing activities............ (98,592) (213,755) (148,291) +-------- --------- --------- +Cash flows from financing activities: +Proceeds from issuance of common stock................... -- -- 98,766 +Purchase of treasury stock............................... -- -- (1,650) +Proceeds from issuance of notes payable.................. -- 9,760 76,392 +Payments of notes payable................................ -- (89,176) (79,766) +Proceeds from exercise of stock options and warrants..... 15,739 6,065 6,963 +-------- --------- --------- +Net cash provided by (used in) financing +activities..................................... 15,739 (73,351) 100,705 +-------- --------- --------- +Net increase (decrease) in cash and cash +equivalents.................................... 48,580 (33,100) 50,611 +Foreign currency translation adjustment.......... (10) (232) (34) +Cash and cash equivalents at beginning of year............. 33,584 66,916 16,339 +-------- --------- --------- +Cash and cash equivalents at end of year................... $ 82,154 $ 33,584 $ 66,916 +======== ========= ========= +Supplemental disclosure of cash flow information: +Net cash received (paid) during the year for: +Interest......................................... $ (532) $ (3,142) $ (10,097) +Income taxes..................................... 13,492 (81,802) (3,319) +The accompanying notes are an integral part of these consolidated financial +statements. +F-7 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED) +Non-cash investing and financing activities: +During March 2002, the Company acquired five SCR electric land-based +drilling rigs through the acquisition of Odin Drilling, Inc., for a purchase +price of $16.9 million. The purchase price consisted of 650,000 shares of common +stock valued at $26.06 per share. A deferred tax liability of $4.1 million was +recorded as a result of the transaction. The transaction was accounted for as a +purchase and the related purchase price was allocated among the rigs based on +their fair values. +During 2001 the Company acquired Jones Drilling Corporation and certain +assets of three other entities affiliated with Jones Drilling Corporation for +$33.0 million, drilling rigs and related equipment from Cleere Drilling Company +for an aggregate purchase price of $25.8 million and six drilling rigs through +three separate transactions for $15.7 million. Of the $74.6 million, +approximately $40.5 million was paid in cash as follows: +(IN THOUSANDS) +-------------- +Purchase price.............................................. $ 74,563 +Less non-cash items: +Common stock issued....................................... (31,417) +Warrants issued........................................... (2,600) +-------- +Total cash paid...................................... $ 40,546 +======== +During May, 2000 the Company acquired a drilling rig in exchange for +certain drilling rig components and drill pipe with a net book value of +approximately $970,000. No gain or loss was recognized on this transaction. +During 2000, the Company acquired WEK Drilling Co., Inc., High Valley +Drilling, Inc., the land drilling operations of Phelps Drilling International, +Ltd., four drilling rigs through two separate transactions, and the drilling and +completion fluids operations of Ambar, Inc., for an aggregate purchase price of +approximately $79.8 million, of which approximately $56.6 million was paid in +cash as follows: +(IN THOUSANDS) +-------------- +Purchase price.............................................. $ 79,767 +Less non-cash items: +Common stock issued....................................... (22,240) +Warrants issued........................................... (900) +-------- +Total cash paid........................................ $ 56,627 +======== +The accompanying notes are an integral part of these consolidated financial +statements. +F-8 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +A DESCRIPTION AND BASIS OF PRESENTATION FOLLOWS: +DESCRIPTION OF BUSINESS -- Patterson-UTI Energy, Inc. and 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, Utah, and Western Canada. The Company owns 324 drilling +rigs. The Company provides drilling fluids, completion fluids, and related +services to oil and natural gas operators in West Texas, Southeast New Mexico, +South Texas, East Texas, Oklahoma, the Gulf Coast regions of Texas and +Louisiana, and the Gulf of Mexico. The Company provides pressure pumping +services to oil and natural gas operators in the Appalachian Basin. The Company +is also engaged in the development, exploration, acquisition, and production of +oil and natural gas. The Company's oil and natural gas operations are focused in +producing regions in West Texas, Southeast New Mexico, and South Texas. +BASIS OF PRESENTATION -- The consolidated financial statements of +Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been prepared +to give retroactive effect to the merger between Patterson Energy, Inc. +("Patterson") and UTI Energy Corp. ("UTI") on May 8, 2001. The transaction was +treated as a reorganization within the meaning of Section 368(a) of the Internal +Revenue Code of 1986, as amended, and accounted for as a pooling of interests +for financial accounting purposes. These financial statements also give +retroactive effect to the two for one stock split in October 2000 by UTI. +A SUMMARY OF THE SIGNIFICANT ACCOUNTING POLICIES FOLLOWS: +PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements +include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All +significant intercompany accounts and transactions have been eliminated. +MANAGEMENT ESTIMATES -- The preparation of financial statements in +conformity with generally accepted accounting principles requires management to +make estimates and assumptions that affect the reported amounts of assets and +liabilities and disclosure of contingent assets and liabilities at the date of +the financial statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those estimates. +REVENUE RECOGNITION -- Generally, revenues are recognized when services are +performed. The Company follows the percentage-of-completion method of accounting +for footage contract drilling arrangements. Under this method, drilling revenues +and costs related to a well in progress are recognized proportionately over the +time it takes to drill the well. Due to the nature of turnkey contract drilling +arrangements and risks therein, the Company follows the completed contract +method of accounting for such arrangements. Under this method, all drilling +advances and costs (including maintenance and repairs) related to a well in +progress are deferred and recognized as revenues and expenses in the period the +well is completed. Provisions for losses on incomplete or in-process wells are +made when estimated total costs are expected to exceed estimated total revenues. +INVENTORIES -- Inventories consist primarily of chemical products to be +used in conjunction with the Company's drilling and completion fluids +activities. The inventories are stated at the lower of cost or market, +determined by the first-in, first-out method. +F-9 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +PROPERTY AND EQUIPMENT -- Property and equipment is carried at cost less +accumulated depreciation. Depreciation is provided on the straight-line method +over the estimated useful lives as defined below. +USEFUL LIVES +(YEARS) +------------- +Drilling rigs and related equipment......................... 2-15 +Office furniture............................................ 3-10 +Buildings................................................... 5-20 +Automotive equipment........................................ 2-7 +Other....................................................... 3-7 +OIL AND NATURAL GAS PROPERTIES -- The Company follows the successful +efforts method of accounting, using the field as its accumulation center for +capitalized costs. Under the successful efforts method of accounting, +exploration costs which result directly in the discovery of oil and natural gas +reserves and all development costs are capitalized. Exploration costs which do +not result directly in discovering oil and natural gas reserves are charged to +expense when such determinations are made. The capitalized costs, consisting of +lease and well equipment, lease acquisition costs, and intangible development +costs, are depreciated, depleted, and amortized on the units-of-production +method, based on petroleum engineer estimates of recoverable proved oil and +natural gas reserves of each respective field. Impairment of proved oil and +natural gas properties is periodically assessed based on estimated future net +cash flows at a field level as determined by an independent reserve engineer. +Impairment expense is included in depreciation, depletion, and amortization in +the accompanying financial statements. +INTANGIBLE ASSETS -- Intangible assets consist primarily of goodwill and +covenants not to compete arising from business combinations (see Notes 2 and 5). +Intangible assets other than goodwill are amortized on a straight line basis +over their estimated useful lives. Covenants not to compete are amortized over +their underlying contractual lives. Prior to 2002, goodwill, representing the +excess of the purchase price over the estimated fair value of the net assets of +the acquired business, was amortized over the period of expected benefit of 15 +years. However, effective January 1, 2002, the Company adopted Statement of +Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," +("SFAS No. 142") which requires that the Company cease amortization of all +intangible assets having indefinite useful economic lives. Such assets, +including goodwill, are not to be amortized until their lives are determined to +be finite, however, a recognized intangible asset with an indefinite useful life +should be tested for impairment annually or on an interim basis if events or +circumstances indicate that the fair value of the asset has decreased below its +carrying value. At December 31, 2002, the Company evaluated its goodwill and +determined that fair value had not decreased below carrying value and no +adjustment to impair goodwill was necessary in accordance with SFAS No. 142. +The following table summarizes depreciation, depletion, amortization, and +impairment expense for 2002, 2001 and 2000 (in millions): +2002 2001 2000 +----- ----- ----- +Depreciation expense........................................ $85.8 $72.6 $52.0 +Depletion expense........................................... 4.4 7.3 3.5 +Amortization expense........................................ 0.3 5.2 6.0 +Impairment of oil and gas properties........................ 0.7 1.1 -- +----- ----- ----- +Total..................................................... $91.2 $86.2 $61.5 +===== ===== ===== +F-10 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +MAINTENANCE AND REPAIRS -- Maintenance and repairs are charged to expense +when incurred. Renewals and betterments which extend the life or improve +existing properties are capitalized. +RETIREMENTS -- Upon disposition or retirement of property and equipment, +the cost and related accumulated depreciation are removed and any resulting gain +or loss is credited or charged to operations. +INVESTMENTS IN EQUITY SECURITIES -- In accordance with Statement of +Financial Accounting Standards No. 115, "Accounting for Certain Investments in +Debt and Equity Securities," ("SFAS No. 115"), investments in Available-for-Sale +equity securities are recorded at fair value. Unrealized gains and losses on +such investments, net of tax, are included in accumulated other comprehensive +loss in our consolidated balance sheet as of December 31, 2002 and are shown as +a separate component of stockholders' equity (see Notes 3 and 6). +EARNINGS PER SHARE -- The Company provides a dual presentation of its +earnings per share; Basic Earnings per Share ("Basic EPS") and Diluted Earnings +per Share ("Diluted EPS") in its Consolidated Statements of Operations. 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, 2002, 2001, and 2000, +dilutive securities, consisting of certain stock options and warrants as +described in Note 11, included in the calculation of Diluted EPS were 2.5 +million shares, 2.8 million shares, and 3.6 million shares, respectively. At +December 31, 2002, 2001, and 2000, there were potentially dilutive securities of +328,500, 490,000, and 46,000, respectively, excluded from the calculation of +Diluted EPS as their exercise prices were greater than the average market price +for the respective year. +INCOME TAXES -- The asset and liability method is used in accounting for +income taxes. Under this method, deferred tax assets and liabilities are +recognized for operating loss and tax credit carryforwards and for the future +tax consequences attributable to differences between the financial statement +carrying amounts of existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the years in which those temporary +differences are expected to be recovered or settled. The effect on deferred tax +assets and liabilities of a change in tax rates is recognized in the results of +operations in the period that includes the enactment date. 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 -- The Company grants stock options to employees +and non-employee directors under stock-based incentive compensation plans, (the +"Plans"). The Company accounts for all stock-based employee compensation plans +under the recognition and measurement provisions of APB Opinion No. 25, +"Accounting for Stock Issued to Employees," ("APB No. 25") and related +interpretations. Under APB No. 25, no stock-based employee compensation cost is +reflected in net income, as all options granted under those plans had an +exercise price equal to or in excess of the market value of the underlying +common stock on the date of grant. The following table illustrates the effect on +net income and earnings per share as if +F-11 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +the company had applied the fair value recognition provisions of FASB Statement +No. 123, "Accounting for Stock-Based Compensation," to stock-based employee +compensation: +YEARS ENDED DECEMBER 31, +----------------------------------------- +2002 2001 2000 +----------- ----------- ----------- +(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) +Net income, as reported............................ $ 2,169 $164,162 $ 37,226 +Deduct: Total stock-based employee compensation +expense determined under fair value based method +for all awards, net of related tax effects(1).... (5,296) (7,053) (6,016) +-------- -------- -------- +Pro forma net income (loss)........................ $ (3,127) $157,109 $ 31,210 +======== ======== ======== +Earnings (loss) per share: +Basic, as reported............................... $ 0.03 $ 2.15 $ 0.52 +======== ======== ======== +Basic, pro forma................................. $ (0.04) $ 2.06 $ 0.44 +======== ======== ======== +Diluted, as reported............................. $ 0.03 $ 2.07 $ 0.50 +======== ======== ======== +Diluted, pro forma............................... $ (0.04) $ 1.98 $ 0.42 +======== ======== ======== +Weighted-average fair value per share of options +granted(1)....................................... $ 15.19 $ 9.97 $ 15.73 +--------------- +(1) See Note 11 for additional information regarding the computations presented +here. +STATEMENT OF CASH FLOWS -- For purposes of reporting cash flows, cash and +cash equivalents include cash on deposit and unrestricted certificates of +deposit with original maturities of 90 days or less. +RECENTLY ISSUED ACCOUNTING STANDARDS -- The Financial Accounting Standards +Board ("FASB") issued Statement of Financial Accounting Standards No. 142, +"Goodwill and Other Intangible Assets," ("SFAS No. 142") in June 2001. SFAS No. +142 supersedes APB Opinion No. 17, "Intangible Assets." Under the provisions of +SFAS No. 142, which the Company adopted on January 1, 2002, goodwill is no +longer amortized but is subject to an annual impairment test. During the years +ended December 31, 2001 and 2000, goodwill amortization totaled approximately +$4.7 million each year. +The FASB issued Statement of Financial Accounting Standards No. 143, +"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001. +SFAS No. 143 addresses financial accounting requirements for retirement +obligations associated with tangible long-lived assets. The provisions of SFAS +No. 143, which the Company adopted on January 1, 2003, will result in the +Company recording a liability of approximately $1.1 million for estimated costs +to be incurred in connection with the abandonment of oil and natural gas +properties in the future. In addition, the cumulative effect of this change in +accounting policy, which will be recorded in the consolidated statement of +income in the first quarter of 2003, will total approximately $500,000, net of +tax. +The FASB issued Statement of Financial Accounting Standards No. 144, +"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No. +144") in August 2001. SFAS No. 144 supersedes SFAS No. 121 and APB Opinion No. +30. The provisions of SFAS No. 144, which the Company adopted on January 1, +2002, did not have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 145, +"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement +No. 13, and Technical Corrections," ("SFAS No. 145") in April 2002. SFAS No. 145 +amends existing authoritative pronouncements to make various +F-12 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +technical corrections, clarify meanings, or describe their applicability under +changed conditions. The provisions of SFAS No. 145, which the Company adopted in +2002, did not have a material impact on the Company's consolidated financial +statements. +The FASB issued Statement of Financial Accounting Standards No. 146, +"Accounting for Costs Associated with Exit or Disposal Activities," ("SFAS No. +146") in June 2002. SFAS No. 146 is effective for exit or disposal activities +that are initiated after December 31, 2002. The provisions of SFAS No. 146 are +not expected to have a material impact on the Company's consolidated financial +statements. +RECLASSIFICATIONS -- Certain reclassifications have been made to the 2001 +and 2000 consolidated financial statements in order for them to conform with the +2002 presentation. +2. MERGERS AND ACQUISITIONS +2002 ACQUISITION +ODIN DRILLING, INC. -- On March 21, 2002, the Company acquired five SCR +electric land-based drilling rigs through the acquisition of Odin Drilling, +Inc., for a purchase price of $16.9 million. The purchase price consisted of +650,000 shares of common stock valued at $26.06 per share. A deferred tax +liability of $4.1 million was recorded as a result of the transaction. The +transaction was accounted for as a purchase and the related purchase price was +allocated among the rigs based on their fair values. +2001 MERGER AND ACQUISITIONS +CLEERE DRILLING COMPANY -- On December 21, 2001, the Company acquired 17 +drilling rigs and related equipment from Cleere Drilling Company for an +aggregate purchase price of $25.8 million. The purchase price consisted of $13.5 +million cash plus 450,000 shares of its common stock and warrants to acquire an +additional 325,000 shares of common stock at an exercise price of $26.75 per +share. The common stock was recorded at $21.55 per share and the warrants were +valued at $8.00 per underlying share of the Company's Common Stock using the +Black-Scholes option valuation model. All of the purchase price was allocated to +the rigs and related equipment acquired. +UTI ENERGY, CORP. -- On February 4, 2001, Patterson entered into an +Agreement and Plan of Merger with UTI providing for the merger of the two +entities. On May 8, 2001, the stockholders of each company approved the merger +and the merger was consummated. Each outstanding share of UTI common stock was +converted into one share of Patterson common stock and each option or warrant +then outstanding representing the right to receive UTI common stock was +converted into the right to purchase Patterson-UTI common stock on an equivalent +basis. A total of 37,782,135 shares of common stock was issued pursuant to the +merger and an additional 3,621,079 shares were reserved for issuance under the +then outstanding UTI stock option plans. Additionally, the stockholders of +Patterson approved an increase in the authorized shares of common stock from 50 +million to 200 million and a name change to "Patterson-UTI Energy, Inc." +The Company incurred $13.1 million in expenses related to the merger. The +expenses consisted of $5.9 million in merger costs which were primarily related +to professional fees paid to investment banking firms, attorneys, accountants +and commercial printers for their professional services rendered and $7.2 +million in restructuring costs and related charges incurred as a result of the +following: +- severance costs and related expenses of $2.8 million, +- closing of duplicate operational facilities of $1.6 million, +- costs of $1.4 million incurred in connection with changes to the +Company's credit facilities (see Note 8), and +F-13 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +- fees and expenses related to the transfer of licenses and leaseholds, and +in some instances the impairment of such leaseholds, the combination or +cancellation of various service contracts and the renegotiation of +certain insurance policies of $1.4 million. +The merger was treated as a reorganization within the meaning of Section +368(a) of the Internal Revenue Code of 1986, as amended, and was accounted for +as a pooling of interests for financial accounting purposes. The consolidated +financial statements give retroactive effect to the merger. Certain adjustments +were made in those periods to conform the previous accounting policies of UTI +with those of Patterson. +JONES DRILLING CORPORATION -- On January 5, 2001, the Company consummated +the transactions contemplated by certain agreements among the Company and Jones +Drilling Corporation and three of its affiliated entities. The acquired assets +consisted of 21 drilling rigs and related equipment and approximately $2.3 +million of net working capital. The purchase price of $33.2 million consisted of +810,070 shares of the Company's common stock valued at $26.8125 per share and +$11.3 million cash plus approximately $240,000 in transaction costs. The +purchase price, net of working capital was allocated among the assets acquired +based on their estimated fair market values as of the date of the transaction. +OTHER -- In January 2001, the Company acquired six drilling rigs, through +three separate transactions, for approximately $15.7 million cash in aggregate. +All of the purchase price was allocated to the rigs acquired. +2000 MERGER AND ACQUISITIONS +AMBAR, INC. -- In October 2000, the Company completed, through a wholly +owned subsidiary, the acquisition of the drilling and completion fluid +operations of Ambar, Inc., a non-affiliated entity with its principal operations +in Louisiana, the Gulf Coast region of South Texas and the Gulf of Mexico. The +purchase price of $12.4 million consisted of cash of $11.7 million and $680,000 +of direct costs incurred related to the acquisition. The assets acquired +included net working capital of approximately $7.8 million (current assets of +$18.2 million and current liabilities assumed of $10.4 million). The purchase +price, net of working capital acquired, was allocated to the fixed assets based +on their estimated fair market values as of the date of the transaction. +OTHER -- In September, 2000, the Company acquired four drilling rigs in two +separate transactions for a total of $7.7 million in cash. The purchase price +was allocated to the rigs acquired. +HIGH VALLEY DRILLING, INC. -- On June 2, 2000, the Company completed the +merger of High Valley Drilling, Inc., a privately held, non-affiliated company, +with and into Patterson-UTI Drilling Company LP, LLLP, a wholly owned subsidiary +of Patterson-UTI. The purchase price of $21.8 million was funded using 1,150,000 +shares of common stock valued at $18 per share, three-year warrants to acquire +127,000 shares at $22 per share and approximately $208,000 of direct costs +incurred related to the transaction. Using a Black-Scholes model, the warrants +were valued at $900,000. The assets acquired consisted of eight drilling rigs +and other related equipment. The purchase price was allocated among such assets +based upon the estimated fair market value of the drilling rigs and related +equipment. +ASSET SWAP. -- On May 15, 2000, the Company, in a non-monetary exchange, +acquired a drilling rig in exchange for certain drilling rig components and +drill pipe with a net book value of approximately $970,000. No gain or loss was +recognized on this transaction. +PHELPS DRILLING INTERNATIONAL LTD. -- On May 5, 2000, the Company acquired +the land drilling operations of Phelps Drilling International Ltd. for $29.6 +million in cash. Phelps' assets and operations are located in the Canadian +provinces of Alberta, Saskatchewan and British Columbia. The acquisition was +accounted for under the purchase method of accounting. The acquired assets +consisted of fourteen land drilling rigs and related equipment. The purchase +price was allocated among such assets based upon the fair market value of the +drilling rigs and related equipment. +F-14 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +WEK DRILLING CO., INC. -- On March 31, 2000, the Company acquired the +outstanding stock of WEK Drilling Co., Inc., a privately held, non-affiliated +drilling company with its principal operations in Southeast New Mexico. The +purchase price of $6.8 million, which is net of cash acquired, was funded using +$5.66 million of proceeds from the Company's existing credit facility and 53,000 +shares of the Company's common stock valued at $29.0625 per share and +approximately $77,000 of direct costs incurred related to the transaction. The +assets acquired consisted of four operable drilling rigs, other related +equipment, and working capital of $1.2 million. Immediately following the +transaction, certain assets unrelated to the oil and natural gas industry were +sold back to one of the previous owners for a cash payment of $1.0 million. The +purchase price of $6.8 million, less the $1.0 million of unrelated assets that +were subsequently sold and the net working capital acquired, was allocated among +the acquired assets based upon the estimated fair market value of the drilling +rigs and related equipment. +3. COMPREHENSIVE INCOME +The following table illustrates the Company's comprehensive income +including the effects of foreign currency translation adjustments for the years +ended December 31, 2002, 2001, and 2000 (in thousands): +2002 2001 2000 +------ -------- ------- +Net income.............................................. $2,169 $164,162 $37,226 +Other comprehensive income: +Foreign currency translation adjustment related to our +Canadian operations................................... 457 (2,326) 30 +Unrealized gain on equity securities, net of tax........ 30 -- -- +------ -------- ------- +Comprehensive income.................................... $2,656 $161,836 $37,256 +====== ======== ======= +4. PROPERTY AND EQUIPMENT +Property and equipment consisted of the following at December 31, 2002 and +2001 (in thousands): +2002 2001 +---------- -------- +Drilling rigs and related equipment......................... $ 895,125 $810,910 +Other equipment............................................. 54,788 46,201 +Oil and natural gas properties.............................. 55,469 51,080 +Buildings................................................... 11,073 10,357 +Land........................................................ 3,779 3,703 +---------- -------- +1,020,234 922,251 +Less accumulated depreciation and depletion................. (392,500) (307,831) +---------- -------- +$ 627,734 $614,420 +========== ======== +5. GOODWILL AND OTHER INTANGIBLE ASSETS +Intangible assets consist primarily of goodwill and covenants not to +compete arising from business combinations (see Note 2). In accordance with SFAS +No. 142, all of our intangible assets that have definite lives are being +amortized on a straight-line basis over their estimated useful lives and +goodwill is evaluated to determine if fair value of the asset has decreased +below its carrying value. At December 31, 2002, we evaluated goodwill and +determined no adjustment to impair goodwill was necessary. Amortization expense +of approximately $4.7 million recognized during 2001 and during 2000, would not +have been recognized under +F-15 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +SFAS No. 142. Goodwill and other intangible assets as of December 31, 2002 and +2001 are as follows (in thousands): +2002 2001 +------- ------- +Goodwill.................................................... $69,860 $69,860 +Accumulated amortization.................................... (19,661) (19,661) +------- ------- +Goodwill, net............................................... 50,199 50,199 +------- ------- +Covenants-not-to-compete and other.......................... $ 1,956 $ 3,635 +Accumulated amortization.................................... (842) (2,200) +------- ------- +Other intangible assets, net................................ 1,114 1,435 +------- ------- +Intangible assets, net...................................... $51,313 $51,634 +======= ======= +Change in the net carrying amount of goodwill for the year ended December +31, 2002 is as follows (in thousands): +DRILLING & +COMPLETION +DRILLING FLUIDS TOTAL +-------- ---------- ------- +Balance at December 31, 2001........................... $40,265 $9,934 $50,199 +Changes to goodwill.................................... -- -- -- +------- ------ ------- +Balance at December 31, 2002........................... $40,265 $9,934 $50,199 +======= ====== ======= +Amortization expense consists of the following (in thousands): +TWELVE MONTHS ENDED DECEMBER 31, +---------------------------------- +2002 2001 2000 +-------- -------- -------- +Goodwill............................................... $ -- $4,665 $4,665 +Covenants-not-to-compete and other..................... 315 507 712 +------ ------ ------ +Goodwill, net.......................................... $ 315 $5,172 $5,953 +====== ====== ====== +Our weighted average amortization period for other intangible assets is +approximately 10 years. The following table shows the estimated amortization +expense for these assets for each of the five succeeding fiscal years (in +thousands): +2003........................................................ $134 +2004........................................................ $ 97 +2005........................................................ $ 97 +2006........................................................ $ 97 +2007........................................................ $ 97 +F-16 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +Had SFAS No. 142 been in effect prior to January 1, 2002, our reported net +income and net income per share would have been as follows (in thousands, except +per share amounts): +TWELVE MONTHS ENDED DECEMBER 31, +--------------------------------- +2002 2001 2000 +-------- ---------- --------- +Net income: +Reported.............................................. $2,169 $164,162 $37,226 +Goodwill amortization................................. -- 4,665 4,665 +------ -------- ------- +Adjusted.............................................. $2,169 $168,827 $41,891 +====== ======== ======= +Basic net income per common share: +Reported.............................................. $ 0.03 $ 2.15 $ 0.52 +Effect of goodwill amortization....................... -- 0.06 0.07 +------ -------- ------- +Adjusted.............................................. $ 0.03 $ 2.21 $ 0.59 +====== ======== ======= +Diluted net income per common share: +Reported.............................................. $ 0.03 $ 2.07 $ 0.50 +Effect of goodwill amortization....................... -- 0.06 0.06 +------ -------- ------- +Adjusted.............................................. $ 0.03 $ 2.13 $ 0.56 +====== ======== ======= +6. INVESTMENT IN EQUITY SECURITIES +On June 14, 2002, the Company purchased 762,597 shares of the common stock +of TMBR/Sharp Drilling, Inc. ("TMBR"), $.10 par value per share, for an +aggregate cash purchase price of $12.7 million, or $16.60 per share plus +approximately $39,000 of additional costs incurred to acquire the shares. The +purchase agreement also included (i) an option for the Company to purchase, and +(ii) an option for the sellers to require the Company to purchase, up to an +additional 195,000 shares of common stock at $16.60 per share. This option was +exercised in October 2002. The company also purchased an additional 101,076 +shares on that date at the same price and incurred an additional $45,000 in +costs to acquire the shares. As of December 31, 2002, the Company owned +approximately 19.9% of the outstanding shares of TMBR. +The accounting treatment of shares representing the Company's investment in +the common stock of TMBR is affected by the Company's ability to sell shares +within one year. As of December 31, 2002, the Company has restrictions on its +ability to sell 892,742 of the TMBR shares within one year. These shares are +reflected in the balance sheet at cost under the cost method of accounting in +accordance with Accounting Principles Board Opinion No. 18, "The Equity Method +of Accounting for Investment in Common Stock," ("APB 18"). The remaining 165,931 +TMBR shares are not restricted from sale within one year. These shares are +classified as Available-for-Sale and are reflected in the balance sheet at fair +value in accordance with SFAS No. 115. Fair value is determined from publicly +quoted market prices as of the balance sheet date. In accordance with SFAS No. +115, unrealized gains and losses recorded as a result of the adjustment to fair +value are reflected directly in stockholders' equity. +F-17 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +The following table summarizes the Company's unrealized gain on its +investment in equity securities as of December 31, 2002 (in thousands, except +share amounts): +COMMON UNREALIZED +SHARES COST GAIN TOTAL +--------- ------- ---------- ------- +TMBR/Sharp Drilling, Inc. +Cost method................................. 892,742 $14,833 $ -- $14,833 +Available-for-Sale.......................... 165,931 2,826 48 2,874 +--------- ------- ---- ------- +1,058,673 $17,659 $ 48 $17,707 +========= ======= ==== ======= +7. ACCRUED EXPENSES +Accrued expenses consisted of the following at December 31, 2002 and 2001 +(in thousands): +2002 2001 +------- ------- +Salaries, wages, payroll taxes and benefits................. $10,573 $13,833 +Workers' compensation liability............................. 15,516 10,683 +Sales, use and other taxes.................................. 2,712 4,758 +Insurance, other than workers' compensation................. 2,605 1,777 +Restructuring and merger related costs...................... 1,029 2,200 +Other....................................................... 3,078 3,257 +------- ------- +$35,513 $36,508 +======= ======= +The following table summarizes activity in restructuring and merger related +accrual accounts for the year ended December 31, 2002 (in thousands): +Balance at December 31, 2001................................ $2,200 +Severance costs and related expenses........................ (324) +Closing of duplicate operational facilities................. (392) +Professional fees........................................... (455) +------ +Balance at December 31, 2002................................ $1,029 +====== +8. NOTES PAYABLE +There were no amounts outstanding under the Company's revolving credit +facility at December 31, 2002 or December 31, 2001. The maximum borrowings under +this revolving credit facility were increased from $90.0 million to $100.0 +million in June 2001 and the term of the facility was also extended to June +2005. A fee of .375% per annum is assessed on the unused facility amount. The +amount used for letters of credit decreases the borrowing base of the facility +on a dollar-for-dollar basis. The revolving credit facility calls for periodic +interest payments at a floating rate ranging from LIBOR plus 1.75% to 2.75%. The +applicable rate above LIBOR (1.75% at December 31, 2002) is based upon our +trailing twelve-month EBITDA (earnings before interest expense, income taxes and +depreciation, depletion and amortization expense). Assets of the Company secure +the facility. The facility has restrictions customary in financial instruments +of this type including restrictions on certain investments, acquisitions and +loans. The facility has no financial covenants unless availability under the +facility is less than $20.0 million. The terms of the facility limit the payment +of dividends without the prior written consent of the lenders. +During 2001, the Company repaid $89.2 million under its existing credit +facilities and other term obligations. The Company incurred expenses of $448,000 +as a result of prepayment penalties and $942,000 +F-18 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +related to deferred financing costs which were unamortized at the time the debt +was extinguished. The penalties and deferred financing costs were included in +restructuring and related charges in 2001. +9. COMMITMENTS, CONTINGENCIES, AND OTHER MATTERS +The Company maintains letters of credit in the aggregate amount of $25.5 +million for the benefit of various insurance companies as collateral for +retrospective premiums and retained losses which could become payable under the +terms of the underlying insurance contracts. These letters of credit expire +variously during each calendar year. No amounts have been drawn under the +letters of credit. +Contingencies -- The Company's contract services and oil and natural gas +exploration and production operations are subject to inherent risks, including +blowouts, cratering, fire, and explosions which could result in personal injury +or death, suspended drilling operations, damage to, or destruction of equipment, +damage to producing formations, and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains general +liability insurance coverage of $2.0 million per occurrence with $4.0 million of +aggregate coverage and excess liability and umbrella coverages up to $50.0 +million per occurrence and in the aggregate. We maintain a $1 million per +occurrence deductible on our general liability insurance coverage and a $750,000 +per occurrence deductible on our workers' compensation insurance coverage. These +levels of self-insurance expose us to increased operating costs and risks. +Net income for the year ended December 31, 2002 includes a charge of $4.7 +million related to the financial failure in 2002 of a workers' compensation +insurance carrier that had provided coverage for the Company in prior years. +The Company believes it is adequately insured for public liability and +property damage to others with respect to its operations. However, such +insurance may not be sufficient to protect the Company against liability for all +consequences of well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover physical damage to, or +loss of, its rigs; however, it does not carry insurance against loss of earnings +resulting from such damage or loss. The Company's lender who has a security +interest in the drilling rigs is named as loss payee on the physical damage +insurance on such rigs. +Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc. +("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson +Petroleum LP, and Patterson-UTI Drilling Company LP, in the Circuit Court, +Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter +agreement entered into in July 2000 between Patterson Petroleum LP and Westfort +concerning the drilling of a daywork well in Mississippi. This lawsuit was filed +by Westfort after Patterson Petroleum LP made demand on Westfort for payment of +the contract drilling services. +In this lawsuit, Westfort alleges breach of contract, fraud, and negligence +causes of action. Westfort seeks alleged monetary damages, the return of shares +of Westfort stock, unspecified damages from alleged lost profits, lost use of +income stream, and additional operating expenses, along with alleged punitive +damages to be determined by the jury, but not less than 25% of Patterson's net +worth. The Company intends to vigorously contest the allegations made by +Westfort and asserts claims against Westfort, including for the monies owed +Patterson Petroleum LP under the letter agreement in the amount of approximately +$5,075,000. +In addition to the Westfort lawsuit, the Company is party to various legal +proceedings arising in the normal course of its business. The Company does not +believe that the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial condition. +F-19 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +10. STOCKHOLDERS' EQUITY +During March 2002, the Company issued 650,000 shares of its common stock as +consideration for the acquisition of Odin Drilling, Inc. (see Note 2). The +common stock was valued at $26.06 per share, its fair market value on the date +the terms of the transaction were agreed upon. +During December 2001, the Company issued 450,000 shares of its common stock +and warrants to acquire an additional 325,000 shares at an exercise price of +$26.75 per share, as partial consideration for the acquisition of 17 drilling +rigs and related equipment from Cleere Drilling Company. The common stock was +recorded at $21.55 per share and the warrants were valued at $8.00 per +underlying share of common stock using the Black-Scholes option valuation model +(see Note 2). +On May 8, 2001, pursuant to the merger between Patterson and UTI, the +Company's stockholders approved an amendment to the Company's charter increasing +the number of authorized shares of the Company's common stock to 200 million. +During January 2001, the Company issued 810,070 shares of its common stock +as partial consideration for the acquisition of Jones Drilling Corporation and +certain assets owned by its related entities (see Note 2). The common stock was +valued at $26.8125 per share, its fair market value on the date of the +transaction. +During September 2000, the Company issued 3,000,000 shares of its common +stock at a public price of $34.50 per share. An underwriting discount of $1.50 +was paid for a net price of $33.00 per share. Net proceeds from the offering +totaled approximately $98.8 million. +During June 2000, the Company issued 1,150,000 shares of its common stock +and three-year warrants to acquire an additional 127,000 shares at an exercise +price of $22.00 per share, as consideration for certain drilling equipment +acquired from High Valley Drilling, Inc. (see Note 2). The common stock was +recorded at $18 per share, its fair market value on the date of purchase and the +warrants were valued at $900,000 using the Black-Scholes option valuation model. +During March 2000, the Company issued 53,000 shares of its common stock as +consideration for certain drilling equipment acquired from WEK Drilling Company, +Inc. The common stock was recorded at $29.0625 per share, its fair market value +on the date of purchase (see Note 2). +F-20 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +11. STOCK OPTIONS AND WARRANTS +EMPLOYEE AND NON-EMPLOYEE DIRECTOR STOCK OPTION PLANS -- The Company has +seven stock option plans of which three are active. The remaining four plans are +dormant and the Company does not intend to grant any further options under such +plans. At December 31, 2002, the Company's stock option plans were as follows: +OPTIONS OPTIONS +AUTHORIZED OPTIONS AVAILABLE +PLAN NAME FOR GRANT OUTSTANDING FOR GRANT +--------- ---------- ----------- --------- +Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan ("1997 Plan")(1)(3).............. 6,000,000 3,881,988 532,536 +Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan +("2001 Plan")(2).......................................... 1,000,000 957,524 8,733 +Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc. ("Non-Employee Director +Plan")(1)................................................. 600,000 112,500 345,000 +Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended ("1995 Non-Employee Director +Plan").................................................... 120,000 28,000 -- +1997 Stock Option Plan of DSI Industries, Inc. ("DSI +Plan")(1)................................................. -- 5,388 -- +Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan ("1996 Plan")(1)............... -- 253,300 -- +Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as +amended ("1993 Plan")..................................... 2,800,000 876,188 -- +--------------- +(1) Plan was assumed by the Company as a part of the merger between Patterson +and UTI. +(2) Plan is for the benefit of employees of the Company, other than officers and +directors of the Company. +(3) Plan is for the benefit of employees of the Company, including officers and +directors of the Company. +The Company's active plans are the 1997 Plan, the 2001 Plan and the +Non-Employee Director Plan. A summary of each of these plans is set forth below. +1997 PLAN +- Administered by the Compensation Committee of the Board of Directors. +- All employees including officers and employee directors are eligible for +awards. +- Vesting schedule is set by the Compensation Committee, however, typically +options vest over 3 or 5 years. +- The Compensation Committee sets the term of the option except that no +Incentive Stock Option ("ISO") can have a term of longer than 10 years. +Typically options granted under the plan have a term of 10 years. +- The options granted under the plan, unless otherwise stated in the grant +thereof, vest upon a change of control as defined in the plan. Options +granted to non-executive employees typically do not vest upon a change of +control. +- All options granted under the plan are granted with an exercise price +equal to or greater than the fair market value of the Company's common +stock at the time the option is granted. +- Although the plan allows for awards of tandem and independent stock +appreciation rights, restricted stock and performance awards, no such +awards have been granted. +- During 2002, the Company increased the options authorized for grant from +3,800,000 to 6,000,000. +F-21 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +2001 PLAN +The terms and conditions of the 2001 Plan are identical to the 1997 Plan +except as follows: +- Officers and directors of the Company are not eligible for grants of +options under the 2001 Plan. +- No ISO's may be awarded under the 2001 Plan. +- Unless the grant states otherwise, options granted under the 2001 Plan do +not vest upon a change of control of the Company. +NON-EMPLOYEE DIRECTOR PLAN +- Administered by the Compensation Committee of the Board of Directors. +- All options vest upon the first anniversary of the option grant. +- Each director receives options to purchase 15,000 shares upon becoming a +director of the Company and options to purchase 7,500 shares on December +31 of each subsequent year in which the director serves as a director of +the Company. +- The exercise price of the options is the fair market value of the +Company's common stock on the date of grant. +Of the four dormant plans administered by the Company, two of the plans +(the 1993 Plan and the 1995 Non-Employee Director Plan) were plans of the +Company prior to the merger of Patterson and UTI and two of the plans (the DSI +Plan and the 1996 Plan) were plans of UTI. +1995 NON-EMPLOYEE DIRECTOR PLAN -- Options granted under the 1995 +Non-Employee Director Plan vest on the first anniversary of the option grant. +1995 Non-Employee Director Plan options have five year terms. All options were +granted with an exercise price equal to the fair market value of the Company's +common stock at the time of grant. +DSI PLAN -- The options granted under the DSI plan typically vested at a +rate of 33% per year with ten year terms. All options were granted with an +exercise price equal to the fair market value of the Company's common stock at +the time of grant. +1996 PLAN -- The options granted under the 1996 plan vested over one, four +and five years as dictated by the Compensation Committee. These options had +terms of five and ten years as dictated by the Compensation Committee. All +options were granted with a strike price equal to the fair market value of the +Company's common stock at the time of grant. +1993 PLAN -- Options granted under the 1993 Plan, typically had terms of 10 +years and vested over five years in 20% increments beginning at the end of the +first year. These options vest in the event of a change of control as defined in +the plan. All options were granted with an exercise price equal to the fair +market value of the Company's common stock at the time of grant. +ADDITIONAL OPTIONS -- In July 2001, the Compensation Committee granted to +each of two non-employee directors of the Company an option to purchase 12,000 +shares of the Company's common stock. These options vested on November 6, 2001 +and terminate four years later on November 5, 2005. The exercise price of each +of the options was $28.625, which was in excess of the fair market value of the +Company's common stock on the date of grant. +F-22 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +A summary of the status of the Company's stock options issued as of +December 31, 2002, 2001, and 2000 and the changes during each of the years then +ended are presented below (in thousands, except weighted average exercise +price): +2002 2001 2000 +--------------------- --------------------- --------------------- +NO. OF WEIGHTED NO. OF WEIGHTED NO. OF WEIGHTED +SHARES OF AVERAGE SHARES OF AVERAGE SHARES OF AVERAGE +UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE +OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE +---------- -------- ---------- -------- ---------- -------- +Outstanding at beginning +of the year............ 6,596 $10.40 5,488 $ 7.57 6,497 $5.72 +Granted................ 2,149 26.77 2,103 16.19 586 18.58 +----- ------ ----- ------ ----- ----- +Total granted....... 8,745 14.42 7,591 9.96 7,083 6.78 +Exercised.............. 2,457 6.41 805 5.26 1,563 3.93 +Surrendered............ 149 15.32 190 14.39 32 11.42 +----- ------ ----- ------ ----- ----- +Outstanding at end of +year................... 6,139 $17.61 6,596 $10.40 5,488 $7.57 +===== ====== ===== ====== ===== ===== +Exercisable at end of +year................... 2,395 $10.88 4,110 $ 7.52 2,672 $6.89 +===== ====== ===== ====== ===== ===== +The following table summarizes information about stock options outstanding +at December 31, 2002: +OPTIONS OUTSTANDING OPTIONS EXERCISABLE +----------------------------------------- ---------------------- +WEIGHTED +AVERAGE WEIGHTED +REMAINING WEIGHTED AVERAGE +NUMBER CONTRACTED AVERAGE NUMBER EXERCISE +RANGE OF EXERCISE PRICES OUTSTANDING LIFE EXERCISE PRICE EXERCISABLE PRICES +------------------------ ----------- ---------- -------------- ----------- -------- +$3.125 to $5.00.............. 1,057,579 6.14 $ 4.55 963,712 $ 4.52 +$5.01 to $20.00.............. 2,819,809 7.53 $15.18 1,318,800 $14.22 +$20.01 to $32.875............ 2,261,500 9.20 $26.74 113,000 $26.25 +--------- ---- ------ --------- ------ +6,138,888 7.90 $17.61 2,395,512 $10.88 +========= ==== ====== ========= ====== +PUBLIC RELATIONS SERVICES STOCK OPTIONS -- In June 1999, the Company issued +options covering a total of 50,000 shares of common stock at an exercise price +of $8.0625 per share to a consultant as partial compensation for public +relations services rendered to the Company. The options granted to the +consultant have an exercise price equal to the fair market value of the stock at +date of grant. The options were fully exercisable upon grant date. All such +options were exercised in 2000. +PRO FORMA STOCK-BASED COMPENSATION DISCLOSURE -- Pro forma information +regarding net income and earnings per share, as described in Note 1, has been +determined as if the Company had accounted for its employee stock options under +the fair value method as defined in that statement. The fair value of each stock +option granted is estimated on the date of grant using the Black-Scholes option +valuation model with the following weighted-average assumptions for grants in +1995 through 2002 respectively; dividend yield of 0.00%; risk-free interest +rates are different for each grant and range from 3.77% to 7.02%; the expected +term is 5 years; and a volatility of 38.68% for all 1995 and 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 and 63.02% for all 2002 +grants. The effects of applying SFAS No. 123 in this pro forma disclosure are +not indicative of future amounts. SFAS No. 123 does not apply to awards prior to +1995. +STOCK PURCHASE WARRANTS -- In December 2001, the Company issued 325,000 +warrants exercisable at $26.75 per share as partial consideration for the +purchase of 17 drilling rigs and related equipment from Cleere +F-23 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +Drilling Company (see Note 2). The warrants were fully exercisable upon the date +of issuance. If not exercised, the warrants will expire on December 21, 2004. +In June 2000, the Company issued 127,000 warrants exercisable at $22 per +share as partial consideration for the purchase of eight drilling rigs and +related equipment from High Valley Drilling, Inc. (see Note 2). The warrants +were fully exercisable upon date of issuance. If not exercised, the warrants +will expire on June 2, 2003. +TABULAR SUMMARY -- The following table summarizes information regarding the +Company's stock options and warrants granted under the provisions of the +aforementioned plans: as well as stock options and warrants issued pursuant to +certain transactions described in Notes 2 and 10: +WEIGHTED AVERAGE +SHARES EXERCISE PRICE +--------- ---------------- +GRANTED +2002..................................................... 2,148,500 $26.77 +2001..................................................... 2,428,500 17.60 +2000..................................................... 713,000 19.19 +EXERCISED +2002..................................................... 2,481,486 $ 6.56 +2001..................................................... 804,581 5.26 +2000..................................................... 1,563,345 3.93 +SURRENDERED +2002..................................................... 149,205 $15.32 +2001..................................................... 190,473 14.39 +2000..................................................... 31,879 11.42 +OUTSTANDING AT YEAR END +2002..................................................... 6,566,101 $18.13 +2001..................................................... 7,048,292 11.36 +2000..................................................... 5,614,846 7.89 +EXERCISABLE AT YEAR END +2002..................................................... 2,822,726 $13.11 +2001..................................................... 4,562,259 9.29 +2000..................................................... 2,799,482 7.58 +12. LEASES +The Company incurred rent expense, consisting primarily of daily rental +charges for the use of drilling equipment, of $5.7 million, $5.9 million, and +$8.6 million, for the years 2002, 2001, and 2000, respectively. The Company's +obligations under non-cancelable operating lease agreements are not material to +the Company's operations. +F-24 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +13. INCOME TAXES +Components of the income tax provision applicable for federal, state and +foreign income taxes are as follows (in thousands): +2002 2001 2000 +-------- -------- ------- +Federal income tax expense (benefit): +Current............................................. $(18,064) $ 82,417 $ 6,932 +Deferred............................................ 21,687 10,887 14,705 +-------- -------- ------- +3,623 93,304 21,637 +State income tax expense (benefit): +Current............................................. (1,811) 4,294 (1) +Deferred............................................ 1,117 661 772 +-------- -------- ------- +(694) 4,955 771 +Foreign income tax expense (benefit): +Current............................................. (2,003) 1,062 -- +Deferred............................................ 744 3,012 470 +-------- -------- ------- +(1,259) 4,074 470 +Total: +Current............................................. $(21,878) $ 87,773 $ 6,931 +Deferred............................................ 23,548 14,560 15,947 +-------- -------- ------- +Total income tax expense.............................. $ 1,670 $102,333 $22,878 +======== ======== ======= +The difference between the statutory federal income tax rate and the +effective income tax rate is summarized as follows: +2002 2001 2000 +---- ---- ---- +Statutory tax rate.......................................... 35.0% 35.0% 35.0% +State income taxes.......................................... 2.8 1.9 1.0 +Foreign taxes............................................... -- -- 0.2 +Permanent differences....................................... 5.7 1.3 1.4 +Other, net.................................................. -- 0.2 .5 +---- ---- ---- +Effective tax rate.......................................... 43.5% 38.4% 38.1% +==== ==== ==== +In assessing the realizability of deferred tax assets, management considers +whether it is more likely than not that some portion or all of the deferred tax +assets will not be realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during the periods in +which those temporary differences become deductible. Management considers the +scheduled reversal of deferred tax liabilities, projected future taxable income, +and tax planning strategies in making this assessment. The Company expects the +deferred tax assets at December 31, 2002 to be realized as a result of the +reversal during the carryforward period of existing taxable temporary +differences giving rise to deferred tax liabilities and the generation of +taxable income in the carryforward period; therefore, no valuation allowance is +necessary. +F-25 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +The tax effect of significant temporary differences representing deferred +tax assets and liabilities and changes therein were as follows (in thousands): +DECEMBER 31, NET DECEMBER 31, NET DECEMBER 31, NET JANUARY 1, +2002 CHANGE 2001 CHANGE 2000 CHANGE 2000 +------------ -------- ------------ -------- ------------ -------- ---------- +Deferred tax assets: +Net operating loss +carryforwards.............. $ -- $ -- $ -- $ (5,850) $ 5,850 $ (5,878) $ 11,728 +Investment tax credit +carryforwards.............. -- -- -- (469) 469 73 396 +AMT credit carryforwards....... 602 -- 602 (3,770) 4,372 543 3,829 +Other.......................... 14,688 6,543 8,145 2,791 5,354 2,215 3,139 +--------- -------- -------- -------- -------- -------- -------- +15,290 6,543 8,747 (7,298) 16,045 (3,047) 19,092 +Valuation allowance............ -- -- -- -- -- -- -- +--------- -------- -------- -------- -------- -------- -------- +Deferred tax assets.......... 15,290 6,543 8,747 (7,298) 16,045 (3,047) 19,092 +Deferred tax liabilities: +Property and equipment basis +difference................. (127,006) (34,147) (92,859) (16,005) (76,854) (17,132) (59,722) +--------- -------- -------- -------- -------- -------- -------- +Net deferred tax +liability................ $(111,716) $(27,604) $(84,112) $(23,303) $(60,809) $(20,179) $(40,630) +========= ======== ======== ======== ======== ======== ======== +Patterson-UTI's investment tax credit carryforward expired in 2000. Net +operating losses were fully utilized in 2001 and the remaining alternative +minimum tax credit may be carried forward indefinitely. Significant other +deferred tax assets consist primarily of workers' compensation allowance of $7.2 +million and bad debt allowance of $3.1 million at December 31, 2002. +14. EMPLOYEE BENEFITS +The Company maintains a 401(k) plan for all eligible employees. The +Company's operating results include expenses of $2.1 million in 2002 and 2001 +and $783,000 in 2000 for the Company's discretionary contributions to the plan. +15. BUSINESS SEGMENTS +The Company conducts its business through four distinct operating +activities: contract drilling of oil and natural gas wells, provision of +drilling and completion fluids services and pressure pumping services to +operators in the oil and natural gas industry, and the exploration, development, +acquisition and production of oil and natural gas. +CONTRACT DRILLING -- The Company markets its contract drilling services to +major and independent oil and natural gas operators. The Company owns 324 +drilling rigs, of which 230 operated in 2002. Currently, 262 of the drilling +rigs are based in Texas and New Mexico (144 in West Texas and New Mexico, 56 in +South Texas, 42 in East Texas, and 20 in North-Central Texas), 41 are based in +Oklahoma, five in Utah, and 16 in Western Canada. Our contract drilling +operations contributed operating income of $7.6 million in 2002. +DRILLING AND COMPLETION FLUIDS -- The Company provides contract drilling +and completion fluids services to oil and natural gas operators in West Texas, +Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast regions +of Texas and Louisiana, and the Gulf of Mexico. Drilling and completion fluids +are used by oil and natural gas operators during the drilling process to control +pressure when drilling oil and natural gas wells. The drilling fluids operations +were added by the Company during 1998 with its acquisition of two companies with +operations in Texas, New Mexico, Oklahoma, and Colorado. Our services were +expanded to include completion fluids in October 2000 with the acquisition of +the drilling and completion +F-26 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +fluids division of Ambar, Inc., which had operations in the coastal areas of +Texas, Louisiana, and in the Gulf of Mexico. Our drilling and completion fluids +services operations had an operating loss of $278,000 in 2002. +PRESSURE PUMPING -- The Company provides pressure pumping services in the +Appalachian Basin. Pressure pumping services consist primarily of well +stimulation and cementing for the completion of new wells and remedial work on +existing wells. Well stimulation involves processes inside a well designed to +enhance the flow of oil, natural gas, or other desired substances from the well. +Cementing is the process of inserting material between the hole and the pipe to +center and stabilize the pipe in the hole. Our pressure pumping operations +contributed operating income of $6.1 million in 2002. +OIL AND NATURAL GAS -- The Company is engaged in the development, +exploration, acquisition, and production of oil and natural gas. Our oil and +natural gas operations contributed operating income of $3.9 million in 2002. +The following tables summarize selected financial information relating to +our business segments (in thousands): +DECEMBER 31, +------------------------------ +2002 2001 2000 +-------- -------- -------- +Revenues: +Contract drilling.................................. $410,295 $839,931 $512,998 +Drilling and completion fluids..................... 69,943 94,456 32,053 +Pressure pumping................................... 32,996 39,600 21,465 +Oil and natural gas................................ 14,723 15,988 15,806 +-------- -------- -------- +Total revenues....................................... $527,957 $989,975 $582,322 +======== ======== ======== +Income before income taxes: +Contract drilling.................................. $ 7,607 $274,514 $ 68,427 +Drilling and completion fluids..................... (278) 3,842 (250) +Pressure pumping................................... 6,090 12,649 3,302 +Oil and natural gas................................ 3,945 756 5,807 +-------- -------- -------- +17,364 291,761 77,286 +Corporate and other................................ (9,266) (11,444) (8,701) +Merger costs....................................... -- (5,943) -- +Restructuring and other charges.................... (4,700) (7,202) -- +Interest income.................................... 1,110 2,080 1,377 +Interest expense................................... (532) (3,142) (10,108) +Other.............................................. (137) 385 250 +-------- -------- -------- +Income before income taxes........................... $ 3,839 $266,495 $ 60,104 +======== ======== ======== +F-27 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +DECEMBER 31, +------------------------------ +2002 2001 2000 +-------- -------- -------- +Identifiable assets: +Contract drilling.................................. $694,020 $681,700 $571,498 +Drilling and completion fluids..................... 34,687 41,724 52,414 +Pressure pumping................................... 35,084 29,473 16,114 +Oil and natural gas................................ 20,854 15,398 21,232 +Corporate and other (a)............................ 157,864 101,347 78,640 +-------- -------- -------- +Total assets......................................... $942,509 $869,642 $739,898 +======== ======== ======== +Depreciation, depletion and amortization: +Contract drilling.................................. $ 80,500 $ 72,797 $ 54,274 +Drilling and completion fluids..................... 2,216 2,644 1,464 +Pressure pumping................................... 2,803 1,895 1,564 +Oil and natural gas................................ 5,251 8,505 3,673 +Corporate and other................................ 446 318 489 +-------- -------- -------- +Total depreciation, depletion and amortization....... $ 91,216 $ 86,159 $ 61,464 +======== ======== ======== +Capital expenditures: +Contract drilling.................................. $ 64,821 $150,788 $116,836 +Drilling and completion fluids..................... 1,571 4,937 10,166 +Pressure pumping................................... 7,399 7,756 4,426 +Oil and natural gas................................ 6,357 7,956 5,341 +Corporate and other................................ 3,695 5,320 -- +-------- -------- -------- +Total capital expenditures........................... $ 83,843 $176,757 $136,769 +======== ======== ======== +--------------- +(a) Corporate assets primarily include cash on hand managed by the parent +corporation and certain deferred federal income tax assets. +F-28 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +Quarterly financial information for the years ended December 31, 2002 and +2001 is as follows (in thousands): +1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL +----------- ----------- ----------- ----------- -------- +2002 +Operating revenues............ $128,223 $125,363 $133,495 $140,876 $527,957 +Operating income (loss)..... 6,428 (6,591) 683 2,878 3,398 +Net income (loss)........... 3,935 (3,845) 249 1,830 2,169 +Earnings (loss) per share: +Basic.................... $ 0.05 $ (0.05) $ 0.00 $ 0.02 $ 0.03 +Diluted.................. $ 0.05 $ (0.05) $ 0.00 $ 0.02 $ 0.03 +2001 +Operating revenues.......... $238,586 $287,564 $289,104 $174,721 $989,975 +Operating income............ 59,160 79,249 98,872 29,891 267,172 +Net income.................. 36,611 48,466 60,382 18,703 164,162 +Earnings per share: +Basic.................... $ 0.48 $ 0.63 $ 0.79 $ 0.24 $ 2.15 +Diluted.................. $ 0.46 $ 0.61 $ 0.77 $ 0.24 $ 2.07 +17. CONCENTRATIONS OF CREDIT RISK +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand deposits, temporary +cash investments, and trade receivables. +The Company believes that it places its demand deposits and temporary cash +investments with high credit quality financial institutions. At December 31, +2002 and 2001, the Company's demand deposits and temporary cash investments +consisted of the following (in thousands): +2002 2001 +-------- -------- +Deposit in FDIC and SIPC-insured institutions under +$100,000.................................................. $ 1,711 $ 5,416 +Deposit in FDIC and SIPC-insured institutions over +$100,000.................................................. 90,464 39,057 +-------- -------- +92,175 44,473 +Less outstanding checks and other reconciling items......... (10,021) (10,889) +-------- -------- +Cash and cash equivalents................................... $ 82,154 $ 33,584 +======== ======== +Concentrations of credit risk with respect to trade receivables are +primarily focused on companies involved in the exploration and development of +oil and natural gas properties. The concentration is somewhat mitigated by the +diversification of customers for which the Company provides drilling services. +As is general industry practice, the Company generally does not require +customers to provide collateral. No significant losses from individual contracts +were experienced during the years ended December 31, 2002, 2001, or 2000. We +recognized bad debt expense for 2002, 2001, and 2000 of $320,000, $2.0 million, +and $570,000, respectively. +The carrying values of cash and cash equivalents, marketable securities, +and trade receivables approximate fair value due to the short-term maturity of +these assets. +F-29 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +18. RELATED PARTY TRANSACTIONS +USE OF ASSETS -- In 2001 and 2000, we leased a 1981 Beech King-Air 90 +airplane owned by SSI Oil and Gas, Inc., an entity beneficially owned 50% by +Cloyce A. Talbott, Patterson-UTI's Chief Executive Officer, and directly owned +50% by A. Glenn Patterson, Patterson-UTI's President/Chief Operating Officer. +Under the terms of the lease, we paid a monthly rental of $9,200, the costs of +fuel, insurance, taxes and maintenance of the aircraft. Such amounts totaled +approximately $212,000 and $194,000 for 2001 and 2000, respectively. +JOINT OPERATION OF OIL AND NATURAL GAS PROPERTIES -- The Company operates +certain oil and natural gas properties in which certain of our affiliated +persons have participated, either individually or through entities they control, +in the prospects or properties in which we have an interest. These +participations, which have been on a working interest basis, have been in +prospects or properties originated or acquired by Patterson-UTI. At December 31, +2002, affiliated persons were working interest owners in 215 of the 256 wells +then being operated by Patterson-UTI. Sales of working interests are made by +Patterson-UTI to reduce its economic risk in the properties. Generally, it is +more efficient for Patterson-UTI to sell the working interests to these +affiliated persons than to market them to unrelated third parties. Sales were +made by Patterson-UTI at its cost, comprised of Patterson-UTI's costs of +acquiring and preparing the working interests for sale. These costs were paid by +the working interest owners on a pro rata basis based upon their working +interest ownership percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests were sold to +unaffiliated persons. The Company made oil and natural gas production payments +(net of royalty) of $6.9 million, $8.3 million, and $13.4 million from these +properties in 2002, 2001, and 2000, respectively, to the aforementioned persons +or entities. These persons or entities reimbursed the Company for joint +operating costs of $5.5 million, $5.9 million, and $8.0 million in 2002, 2001, +and 2000, respectively. +OTHER -- In 2002 and 2001, we paid approximately $279,000 and $387,000, +respectively, to TMP Truck and Trailer LP ("TMP"), and entity owned by Thomas M. +Patterson (son of A. Glenn Patterson), for certain equipment and metal +fabrication services. Purchases from TMP were at then current market prices. +19. SUBSEQUENT EVENT +Subsequent to December 31, 2002, the Company purchased seven drilling rigs +in two separate transactions, for an aggregate purchase price of $16.5 million +in cash. The acquisitions were funded out of the Company's existing cash. +20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) +In 2001 and 2000, the Company's oil and natural gas operations were not +material to the Company's consolidated operations and therefore did not require +separate disclosure of certain supplemental data. +OIL AND GAS EXPENDITURES AND CAPITALIZED COSTS +Gross oil and natural gas expenditures by the Company for the year ended +December 31, 2002 are summarized below (in thousands): +Property acquisition costs.................................. $ 905 +Exploration costs........................................... 6,267 +Development costs........................................... 845 +------ +$8,017 +====== +F-30 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) -- (CONTINUED) +The aggregate amount of capitalized costs of oil and natural gas properties +as of December 31, 2002 is comprised of the following (in thousands): +Proved properties........................................... $44,849 +Accumulated depreciation and depletion...................... (35,684) +------- +$ 9,165 +======= +RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES: +Oil and natural gas sales................................... $12,738 +Gain on sale of oil and natural gas properties.............. 303 +------- +13,041 +------- +Costs and expenses: +Lease operating and production costs........................ 3,068 +Exploration costs including dry holes and abandonments...... 785 +Depreciation and depletion.................................. 4,633 +Impairment of oil and natural gas properties................ 727 +------- +9,213 +------- +Results of operations for oil and natural gas producing +activities, before taxes.................................. $ 3,828 +======= +OIL AND NATURAL GAS RESERVE QUANTITIES: +The following table sets forth information with respect to quantities of +net proved developed oil and natural gas reserves and changes in those reserves +for the years ended December 31, 2002, 2001, and 2000 (in +F-31 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) -- (CONTINUED) +thousands). The quantities were estimated by an independent petroleum engineer. +The Company's proved developed oil and natural gas reserves are located entirely +within the United States. +OIL (BBLS) GAS (MCF) +---------- --------- +Estimated quantity, January 1, 2000......................... 1,209 4,118 +Revision in previous estimates.............................. 61 (157) +Extensions, discoveries and other additions................. 134 1,303 +Production.................................................. (275) (1,384) +------ ------- +Estimated quantity, January 1, 2001......................... 1,129 3,880 +Revision in previous estimates.............................. 16 609 +Extensions, discoveries and other additions................. 175 1,862 +Sales of reserves........................................... (1) -- +Production.................................................. (272) (1,717) +------ ------- +Estimated quantity, January 1, 2002......................... 1,047 4,634 +Revision in previous estimates.............................. 145 2,103 +Extensions, discoveries and other additions................. 331 1,420 +Sales of reserves........................................... (12) (110) +Production.................................................. (284) (1,807) +------ ------- +Estimated quantity, January 1, 2003......................... 1,227 6,240 +====== ======= +ESTIMATES OF RESERVES AND PRODUCTION PERFORMANCE ARE SUBJECTIVE AND MAY +CHANGE MATERIALLY AS ACTUAL PRODUCTION INFORMATION BECOMES AVAILABLE. +STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS OF PROVED DEVELOPED OIL AND +NATURAL GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (IN THOUSANDS): +YEAR ENDED DECEMBER 31, +--------------------------- +2002 2001 2000 +------- ------- ------- +Future gross revenues................................... $68,165 $32,674 $48,161 +Future development and production costs................. (22,149) (13,077) (16,270) +Future income tax expense (a)........................... (15,964) (5,110) (8,617) +------- ------- ------- +Future net cash flows................................... 30,052 14,487 23,274 +Discount at 10% per annum............................... (8,952) (3,773) (6,634) +------- ------- ------- +Standardized measure of discounted future net cash +flows................................................. $21,100 $10,714 $16,640 +======= ======= ======= +--------------- +(a) Future income taxes are computed by applying the statutory tax rate to +future net cash flows less the tax basis of the properties and net operating +loss attributable to oil and gas operations and investment tax credit +carryforwards as of year-end; statutory depletion and tax credits applicable +to future oil and gas-producing activities are also considered in the income +tax computation. +F-32 +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) +20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA +(UNAUDITED) -- (CONTINUED) +CHANGES IN THE STANDARDIZED MEASURE OF NET CASH FLOWS OF PROVED DEVELOPED OIL +AND GAS RESERVES DISCOUNTED AT 10% PER ANNUM (IN THOUSANDS): +YEAR ENDED DECEMBER 31, +--------------------------- +2002 2001 2000 +------- ------- ------- +Standardized measure at beginning of year............... $10,714 $16,640 $12,082 +Sales and transfers of oil and gas produced, net of +production costs...................................... (8,342) (8,684) (7,982) +Net changes in sales price and future production and +development costs..................................... 4,888 (10,670) 5,819 +Extensions, discoveries and improved recovery, less +related costs......................................... 6,017 2,870 4,064 +Sales of minerals-in-place.............................. (30) (1) -- +Revision of previous quantity estimates................. 4,315 (2,824) 1,255 +Accretion of discount................................... 1,531 2,440 1,873 +Other................................................... (9,358) 13,588 (2,435) +Net change in income taxes.............................. 11,365 (2,645) 1,964 +------- ------- ------- +Standardized measure at end of year..................... $21,100 $10,714 $16,640 +======= ======= ======= +F-33 +PATTERSON-UTI ENERGY, INC. +SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS +(IN THOUSANDS) +ADDITIONS(1) +------------------------ +CHARGED TO ACQUIRED +BEGINNING COSTS AND THROUGH ENDING +DESCRIPTION BALANCE EXPENSES ACQUISITION DEDUCTIONS(2) BALANCE +----------- --------- ---------- ----------- ------------- ------- +YEAR ENDED DECEMBER 31, 2002 +Deducted from asset accounts: +Allowance for doubtful accounts....... $4,021 $ 320 $ -- $1,197 $3,144 +YEAR ENDED DECEMBER 31, 2001 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,462 $2,045 $ -- $1,486 $4,021 +YEAR ENDED DECEMBER 31, 2000 +Deducted from asset accounts: +Allowance for doubtful accounts....... $3,508 $ 570 $800 $1,416 $3,462 +--------------- +(1) Net of recoveries. +(2) Uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this report to +be signed on its behalf by the undersigned, thereunto duly authorized. +PATTERSON-UTI ENERGY, INC. +Date: February 7, 2003 By: /s/ CLOYCE A. TALBOTT +--------------------------------------------- +Cloyce A. Talbott +Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this +report has been signed by the following persons on behalf of Patterson-UTI +Energy, Inc. and in the capacities indicated as of February 7, 2003. +SIGNATURE TITLE +--------- ----- +/s/ MARK S. SIEGEL Chairman of the Board +--------------------------------------------- +Mark S. Siegel +/s/ CLOYCE A. TALBOTT Chief Executive Officer and Director +--------------------------------------------- +Cloyce A. Talbott +(Principal Executive Officer) +/s/ A. GLENN PATTERSON President, Chief Operating Officer and +--------------------------------------------- Director +A. Glenn Patterson +/s/ JONATHAN D. NELSON Vice President -- Finance, Chief Financial +--------------------------------------------- Officer, Secretary and Treasurer +Jonathan D. Nelson +(Principal Accounting Officer) +/s/ KENNETH N. BERNS Director +--------------------------------------------- +Kenneth N. Berns +/s/ NADINE C. SMITH Director +--------------------------------------------- +Nadine C. Smith +/s/ CURTIS W. HUFF Director +--------------------------------------------- +Curtis W. Huff +/s/ ROBERT C. GIST Director +--------------------------------------------- +Robert C. Gist +/s/ KENNETH R. PEAK Director +--------------------------------------------- +Kenneth R. Peak +/s/ STEPHEN J. DEGROAT Director +--------------------------------------------- +Stephen J. DeGroat +CERTIFICATIONS +I, Cloyce A. Talbott, certify that, +(1) I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, +Inc; +(2) Based on my knowledge, this annual 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 annual +report; +(3) Based on my knowledge, the financial statements, and other financial +information included in this annual report, fairly present in all material +respects the financial condition, results of operations and cash flows of the +registrant as of, and for, the periods presented in this annual report; +(4) The registrant's other certifying officer and I are responsible for +establishing and maintaining disclosure controls and procedures (as defined in +Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: +(a) designed such disclosure controls and procedures 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 annual report is +being prepared; +(b) evaluated the effectiveness of the registrant's disclosure controls +and procedures as of a date within 90 days prior to the filing date of +this annual report (the "Evaluation Date"); and +(c) presented in this annual report our conclusions about the +effectiveness of the disclosure controls and procedures based on our +evaluation as of the Evaluation Date; +(5) The registrant's other certifying officer and I have disclosed, based on +our most recent evaluation, to the registrant's auditors and the audit +committee of the registrant's board of directors (or persons performing the +equivalent functions): +(a) all significant deficiencies in the design or operation of internal +controls which could adversely affect the registrant's ability to +record, process, summarize and report financial data and have +identified for the registrant's auditors any material weaknesses in +internal controls; and +(b) any fraud, whether or not material, that involves management or +other employees who have a significant role in the registrant's +internal controls; and +(6) The registrant's other certifying officer and I have indicated in this +annual report whether or not there were significant changes in internal +controls or in other factors that could significantly affect internal controls +subsequent to the date of our most recent evaluation, including any corrective +actions with regard to significant deficiencies and material weaknesses. +Date: February 7, 2003 /s/ CLOYCE A. TALBOTT +------------------------ +Cloyce A. Talbott +Chief Executive Officer +CERTIFICATIONS +I, Jonathan D. Nelson, certify that: +(1) I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, +Inc.; +(2) Based on my knowledge, this annual 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 annual +report; +(3) Based on my knowledge, the financial statements, and other financial +information included in this annual report, fairly present in all material +respects the financial condition, results of operations and cash flows of the +registrant as of, and for, the periods presented in this annual report. +(4) The registrant's other certifying officer and I are responsible for +establishing and maintaining disclosure controls and procedures (as defined in +Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have +(a) designed such disclosure controls and procedures 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 annual report is +being prepared; +(b) evaluated the effectiveness of the registrant's disclosure controls +and procedures as of a date within 90 days prior to the filing date of +this annual report (the "Evaluation Date"), and +(c) presented in this annual report our conclusions about the +effectiveness of the disclosure controls and procedures based on our +evaluation as of the Evaluation Date; +(5) The registrant's other certifying officer and I have disclosed, based on our +most recent evaluation, to the registrant's auditors and the audit committee of +the registrant's board of directors (or persons performing the equivalent +functions). +(a) all significant deficiencies in the design or operation of internal +controls which could adversely affect the registrant's ability to +record, process, summarize and report financial data and have +identified for the registrant's auditors any material weaknesses in +internal controls; and +(b) any fraud, whether or not material, that involves management or +other employees who have a significant role in the registrant's +internal controls; and +(6) The registrant's other certifying officer and I have indicated in this +annual report whether or not there were significant changes in internal +controls or in other factors that could significantly affect internal controls +subsequent to the date of our most recent evaluation, including any corrective +actions with regard to significant deficiencies and material weaknesses. +Date: February 7, 2003 +/s/ Jonathan D. Nelson +---------------------------------------- +Jonathan D. Nelson +Vice President, Chief Financial Officer, +Secretary and Treasurer +EXHIBIT INDEX +EXHIBIT +NUMBER DESCRIPTION +------- ----------- +2.1 Agreement and Plan of Merger dated March 10, 2002 among +Patterson-UTI Energy, Inc., Patterson-UTI Drilling Company +LP, LLLP and Odin Drilling, Inc.(1) +2.2 Stock Purchase Agreement dated as of June 11, 2002 by and +among Patterson-UTI Energy, Inc. and Roper Family +Properties, Ltd., Estate of Joe G. Roper, Patricia R. +Elledge, Judy Kathleen Roper Davis, Jeanie Elisabeth +Cornelius and J. Mark Roper.(2) +2.3 Stock Purchase Agreement dated as of October 28, 2002 by and +between Patterson-UTI Energy, Inc. and J. Mark Roper.(3) +3.1 Restated Certificate of Incorporation.(4) +3.1.1 Certificate of Correction of Restated Certificate of +Incorporation.(5) +3.2 Amended and Restated Bylaws.(5) +3.3 Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust +Company.(6) +3.3.1 Amendment to Rights Agreement dated as of October 23, +2001.(7) +4.1 Excerpt from Restated Certificate of Incorporation of +Patterson-UTI Energy, Inc. regarding authorized Common Stock +and Preferred Stock.(8) +4.2 Certificate of Designation.(9) +4.2.1 Amendment to Certificate of Designation.(5) +4.3 Registration Rights Agreement with Bear, Stearns and Co. +Inc., dated March 25, 1994, as assigned by REMY Capital +Partners III, L.P.(5) +4.4 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as +amended.(10)* +4.5 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock +Option Plan, as amended.(11)* +4.6 Patterson-UTI Energy, Inc. Amended and Restated 1997 +Long-Term Incentive Plan.(12)* +4.7 Amended and Restated Non-Employee Director Stock Option Plan +of Patterson-UTI Energy, Inc.(13)* +4.8 Amended and Restated Patterson-UTI Energy, Inc. 1996 +Employee Stock Option Plan.(13)* +4.9 1997 Stock Option Plan of DSI Industries, Inc.(12)* +4.10 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.).(5)* +4.11 Stock Option Agreement dated July 20, 2001 between +Patterson-UTI Energy, Inc. and Stephen J. DeGroat (a +non-employee director of Patterson-UTI Energy, Inc.).(5)* +10.1 For additional material contracts, see Exhibits 4.3 through +4.11. +10.2 Amended and Restated Loan and Security Agreement, dated July +26, 2002.(8) +10.3 Revolving Loan Promissory Note, dated July 26, 2002 dated +May 18, 2000.(8) +10.4 Amended and Restated Guaranty Agreement, dated July 26, +2002.(8) +10.5 Amended and Restated Pledge Agreement, dated July 26, +2002.(8) +10.6 Model Form Operating Agreement.(14) +10.7 Form of Drilling Bid Proposal and Footage Drilling +Contract.(14) +10.8 Form of Turnkey Drilling Agreement.(14) +21.1 Subsidiaries of the Registrant. +23.1 Consent of Independent Accountants -- PricewaterhouseCoopers +LLP. +23.2 Consent of Independent Auditors -- Ernst & Young LLP. +23.3 Consent of Independent Petroleum Engineer -- M. Brian +Wallace, P.E. +99.1 Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as Adopted pursuant +to Section 906 of the Sarbanes-Oxley Act of 2002. +--------------- +(1) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended March 31, 2002. +(2) Incorporated herein by reference to Item 7, "Material to be Filed as +Exhibits" to Amendment No. 1 to Schedule 13D filed on October 31, 2002. +(3) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2002. +(4) Incorporated herein by reference to Item 7, "Financial Statements and +Exhibits" to Form 8-K dated and filed on May 8, 2001. +(5) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement +Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the +fiscal year ended December 31, 2001. +(6) Incorporated by reference to Item 2, "Exhibits" to Registration Statement +on Form 8-A filed on January 14, 1997. +(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed +on October 31, 2001. +(8) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form +8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on +August 1, 2001. +(9) Incorporated herein by reference to Item 2, "Exhibits" to Registration +Statement on Form 8-A (File No. 000-22664) filed on January 14, 1997. +(10) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on March 13, 1998. +(11) Incorporated herein by reference to Item 8, "Exhibits" to Registration +Statement on Form S-8 (File No. 33-39471) filed on November 4, 1997. +(12) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470) +filed on July 25, 2001. +(13) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective +Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466) +filed on July 25, 2001. +(14) Incorporated by reference to Item 27, "Exhibits" to Registration Statement +on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993. +* Management Contract or Compensatory Plan identified as required by Item +15(a)(3) of Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/filing_metadata.csv b/raw/filings/0000889900/2002/0000950134-03-001857/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..2e10eb83bd6c692cd9627776b81fe63df884d000 --- /dev/null +++ b/raw/filings/0000889900/2002/0000950134-03-001857/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2003-02-07,2002-12-31,2003-02-07T22:19:02.000Z,0000950134-03-001857,d02863e10vk.txt,FORM 10-K,280548,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013403001857/d02863e10vk.txt,https://www.sec.gov/Archives/edgar/data/889900/000095013403001857/,2002,2002,1 diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/item1.txt b/raw/filings/0000889900/2002/0000950134-03-001857/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/item13.txt b/raw/filings/0000889900/2002/0000950134-03-001857/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3d03584cff734b89484cd78dad36f817d93b850d --- /dev/null +++ b/raw/filings/0000889900/2002/0000950134-03-001857/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. +The information required by this Item is incorporated herein by reference +to the Proxy Statement. +32 \ No newline at end of file diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/item9a.txt b/raw/filings/0000889900/2002/0000950134-03-001857/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/rp_note.txt b/raw/filings/0000889900/2002/0000950134-03-001857/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..2faef1f56922faf7142a67622779902cdfe3ed16 --- /dev/null +++ b/raw/filings/0000889900/2002/0000950134-03-001857/rp_note.txt @@ -0,0 +1,34 @@ +18. RELATED PARTY TRANSACTIONS +USE OF ASSETS -- In 2001 and 2000, we leased a 1981 Beech King-Air 90 +airplane owned by SSI Oil and Gas, Inc., an entity beneficially owned 50% by +Cloyce A. Talbott, Patterson-UTI's Chief Executive Officer, and directly owned +50% by A. Glenn Patterson, Patterson-UTI's President/Chief Operating Officer. +Under the terms of the lease, we paid a monthly rental of $9,200, the costs of +fuel, insurance, taxes and maintenance of the aircraft. Such amounts totaled +approximately $212,000 and $194,000 for 2001 and 2000, respectively. +JOINT OPERATION OF OIL AND NATURAL GAS PROPERTIES -- The Company operates +certain oil and natural gas properties in which certain of our affiliated +persons have participated, either individually or through entities they control, +in the prospects or properties in which we have an interest. These +participations, which have been on a working interest basis, have been in +prospects or properties originated or acquired by Patterson-UTI. At December 31, +2002, affiliated persons were working interest owners in 215 of the 256 wells +then being operated by Patterson-UTI. Sales of working interests are made by +Patterson-UTI to reduce its economic risk in the properties. Generally, it is +more efficient for Patterson-UTI to sell the working interests to these +affiliated persons than to market them to unrelated third parties. Sales were +made by Patterson-UTI at its cost, comprised of Patterson-UTI's costs of +acquiring and preparing the working interests for sale. These costs were paid by +the working interest owners on a pro rata basis based upon their working +interest ownership percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests were sold to +unaffiliated persons. The Company made oil and natural gas production payments +(net of royalty) of $6.9 million, $8.3 million, and $13.4 million from these +properties in 2002, 2001, and 2000, respectively, to the aforementioned persons +or entities. These persons or entities reimbursed the Company for joint +operating costs of $5.5 million, $5.9 million, and $8.0 million in 2002, 2001, +and 2000, respectively. +OTHER -- In 2002 and 2001, we paid approximately $279,000 and $387,000, +respectively, to TMP Truck and Trailer LP ("TMP"), and entity owned by Thomas M. +Patterson (son of A. Glenn Patterson), for certain equipment and metal +fabrication services. Purchases from TMP were at then current market prices. \ No newline at end of file diff --git a/raw/filings/0000889900/2002/0000950134-03-001857/rpt_disclosure.txt b/raw/filings/0000889900/2002/0000950134-03-001857/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/filing.txt b/raw/filings/0000889900/2003/0000950134-04-001065/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..1959f54ace4040edb30f593437a9cb73b1d5e8c9 --- /dev/null +++ b/raw/filings/0000889900/2003/0000950134-04-001065/filing.txt @@ -0,0 +1,8141 @@ +10-K +1 +d12235e10vk.htm +FORM 10-K +e10vk +Table of Contents +UNITED STATES SECURITIES AND EXCHANGE +COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR +15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, +2003 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 +OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, Inc. +(Exact name of registrant as specified in its +charter) +Delaware +75-2504748 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +4510 Lamesa Highway, Snyder, Texas +79549 +(Address of principal executive +offices) +(Zip Code) +Registrant’s telephone number, including +area code: +(325) 574-6300 +Securities Registered Pursuant to 12(b) of the +Act: None +Securities Registered Pursuant to 12(g) of the +Act: +(Title of class) +Common Stock, $.01 Par Value +Indicate by check mark whether the registrant +(1) has filed all reports required to be filed by +Section 13 or 15 (d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter +period that the registrant was required to file such reports), +and (2) has been subject to such filing requirements for +the past +90 days. Yes þ No o +Indicate by check mark if disclosure of +delinquent filers pursuant to Item 405 of +Regulation S-K is not contained herein, and will not be +contained, to the best of the registrant’s knowledge, in +definitive proxy or information statements incorporated by +reference in Part III of this Form 10-K or any +amendment to this +Form 10-K. o +Indicate by check mark whether the registrant is +an accelerated filer (as defined in Rule 12b-2 of the +Act). Yes þ No o +The aggregate market value of the voting and +non-voting common equity held by non-affiliates of the +registrant as of June 30, 2003, the last business day of +the registrant’s most recently completed second fiscal +quarter was $2,441,241,719, calculated by reference to the +closing price of $32.37 for the common stock on the Nasdaq +National Market on that date. +As of February 2, 2004, the registrant had +outstanding 81,055,467 shares of common stock, $.01 par value, +its only class of voting stock. +Documents incorporated by reference: +Definitive Proxy Statement for the 2004 Annual +Meeting of Stockholders (Part III) +TABLE OF CONTENTS +PART I +Items 1 and 2. Business and Properties. +Item 3. Legal Proceedings. +Item 4. Submission of Matters to a Vote of Security Holders. +PART II +Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters. +Item 6. Selected Financial Data. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations +Item 7A. Quantitative and Qualitative Disclosures About Market Risk +Item 8. Financial Statements and Supplementary Data. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Item 9A. Controls and Procedures. +PART III +Item 10. Directors and Executive Officers of the Registrant. +Item 11. Executive Compensation. +Item 12. Security Ownership of Certain Beneficial Owners and Management. +Item 13. Certain Relationships and Related Transactions. +Item 14. Principal Accountant Fees and Services. +PART IV +Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K. +SIGNATURES +EXHIBIT INDEX +EX-10.2 Change in Control Agreement-M. Siegel +EX-10.3 Change in Control Agreement-G. Patterson +EX-10.4 Change in Control Agreement-C. Talbott +EX-10.5 Change in Control Agreement-K. Berns +EX-10.6 Change in Control Agreement-J. Nelson +EX-10.7 Change in Control Agreement-J. Vollmer III +EX-14.1 Code of Business Conduct and Ethics +EX-21.1 Subsidiaries of the Registrant +EX-23.1 Consent of PricewaterhouseCoopers LLP +EX-23.2 Consent of M. Brian Wallace, P.E. +EX-31.1 Certification of CEO - Rule 13a-14(a) +EX-31.2 Certification of CFO - Rule 13a-14(a) +EX-32.1 Certification of CEO & CFO - Section 906 +Table of Contents +This Report on Form 10-K (including +documents incorporated by reference herein) contains statements +with respect to our expectations and beliefs as to future +events. These types of statements are +“forward-looking” and subject to uncertainties. +Readers are cautioned that such forward-looking statements +should be read in conjunction with our disclosures under the +heading: “Forward Looking Statements and Cautionary +Statements for Purposes of the ‘Safe Harbor’ +Provisions of the Private Securities Litigation Reform Act of +1995” beginning on page 15. +This Report on Form 10-K, along with our +Quarterly Reports on Form 10-Q, Current Reports on +Form 8-K, and amendments to those reports filed or +furnished pursuant to Section 13(a) or 15(d) of the +Securities Exchange Act of 1934, are available through our +Internet website (www.patenergy.com) as soon as reasonably +practicable after we electronically file such material with, or +furnish it to, the SEC. +PART I +Items 1 and +2. Business and +Properties. +Overview +Based on publicly available information, we +believe we are the second largest owner of land-based drilling +rigs in North America. The Company was formed in 1978 and +reincorporated in 1993 as a Delaware corporation. Our contract +drilling business operates primarily in: +• +Texas, +• +New Mexico, +• +Oklahoma, +• +Louisiana, +• +Mississippi, +• +Colorado, +• +Utah, +• +Wyoming, and +• +Western Canada (Alberta, British Columbia and +Saskatchewan). +As of December 31, 2003, we had a drilling +fleet of 343 drilling rigs. A drilling rig includes the +structure, power source, and machinery necessary to cause a +drill bit to penetrate earth to a depth desired by the customer. +We provide pressure pumping services to oil and +natural gas operators primarily in the Appalachian Basin. These +services consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids, and related services +to oil and natural gas operators in West Texas, Southeast New +Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast +regions of Texas and Louisiana, and the Gulf of Mexico. Drilling +and completion fluids are used by oil and natural gas operators +during the drilling process to control pressure when drilling +oil and natural gas wells. We are also engaged in the +development, exploration, acquisition and production of oil and +natural gas. Our oil and natural gas operations are focused +primarily in producing regions in West Texas, Southeast New +Mexico, South Texas and Mississippi. +Patterson/UTI Merger +Patterson Energy, Inc. and UTI Energy Corp. +consummated a merger on May 8, 2001. The transaction was +treated as a reorganization within the meaning of +Section 368 (a) of the Internal Revenue Code of 1986, +as amended, and accounted for as a pooling of interests for +financial accounting purposes. Historical financial +1 +Table of Contents +statements and related financial and statistical +data contained in this Report have been restated to provide for +the retroactive effect of the merger. +Industry Segments +Our revenues, operating profits/(losses) and +identifiable operating assets are attributable to four industry +segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas development, exploration, +acquisition and production. +With respect to these four segments: +• +the contract drilling segment had operating +profits in 2003, 2002 and 2001, +• +the pressure pumping segment had operating +profits in 2003, 2002 and 2001, +• +the drilling and completion fluids segment had +operating losses in 2003 and 2002 and an operating profit in +2001, and +• +the oil and natural gas segment had operating +profits in 2003, 2002 and 2001. +See “Management’s Discussion and +Analysis of Financial Condition and Results of Operations” +and Note 16 of Notes to Consolidated Financial Statements +included as a part of Items 7 and 8, respectively, of +this Report for financial information pertaining to these +industry segments. +Contract Drilling Operations +General — +We market our contract drilling services to major and +independent oil and natural gas operators. As of +December 31, 2003, we owned 343 drilling rigs which are +based in the following regions: +• +143 in West Texas and New Mexico, +• +56 in South Texas, +• +42 in the Ark-La-Tex region and Mississippi, +• +70 in the Mid-Continent region (Oklahoma and +North Central Texas), +• +16 in the Rocky Mountain region (Colorado, Utah +and Wyoming), and +• +16 in Western Canada (Alberta, British Columbia +and Saskatchewan). +Of our drilling rigs, 39 are SCR electric rigs +and 304 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. Our drilling rigs have rated +maximum depth capabilities ranging from 4,000 feet to 30,000 +feet. +Drilling rigs are typically equipped with: +• +engines, +• +drawworks or hoists, +• +derricks or masts, +• +pumps to circulate the drilling fluid, +• +blowout preventers, +2 +Table of Contents +• +drill string (pipe), and +• +other related equipment. +Over time, many of the components on a drilling +rig are replaced or rebuilt. We spend significant funds each +year on an ongoing program of modifying and upgrading our +drilling rigs to ensure that our drilling equipment is well +maintained and competitive. During fiscal years 2003, 2002, and +2001, we spent approximately $95 million, $69 million, +and $151 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. Our drilling rigs are utilized for +both developmental and exploratory drilling and can be used for +either vertical or horizontal drilling. +Our contract drilling operations depend on the +availability of: +• +drill pipe, +• +bits, +• +replacement parts and other related rig equipment, +• +fuel, and +• +qualified personnel, +some of which have been in short supply from time +to time. +Drilling +Contracts — Most of our +drilling contracts are with established customers and are +obtained on a competitive bid or negotiated basis. Typically, +the contracts are entered into for short-term periods and cover +the drilling of a single well or a series of wells. +The drilling contracts obligate us to provide and +operate a drilling rig and to pay certain operating expenses, +including wages of drilling personnel and necessary maintenance +expenses. The contracts are subject to termination by the +customer on short notice. We generally indemnify our customers +against claims by our employees and claims arising from surface +pollution caused by spills of fuel, lubricants, and other +solvents within our control. The customers generally indemnify +us against claims arising from other surface and subsurface +pollution, except claims arising 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 bids for each contract +depend upon: +• +the location, depth, and anticipated complexity +of the well, +• +the on-site drilling conditions, +• +the equipment to be used, +• +our estimate of the risks involved, +• +the estimated duration of the work to be +performed, +• +the availability of drilling rigs, and +• +other factors particular to each proposed well. +Daywork Contracts +Under daywork contracts, we provide the drilling +rig and crew to the customer. The customer supervises the +drilling of the well. Our compensation is based on a contracted +rate per day during the period the drilling rig is utilized. We +generally receive a lower rate when the drilling rig is moving, +or when drilling operations are interrupted or restricted by +conditions beyond our control. In addition, daywork contracts +typically provide separately for mobilization of the drilling +rig. +3 +Table of Contents +Footage Contracts +Under footage contracts, we contract to drill a +well to a certain depth under specified conditions for a fixed +price per foot. The customer provides drilling fluids, casing, +cementing, and well design expertise. These 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 margins over those that would be attainable under a +daywork contract. Margins are reduced and losses may be incurred +if the well requires more days to drill to the contracted depth +than estimated. Footage contracts generally contain greater +risks for a drilling contractor than daywork contracts. Under +footage contracts, the drilling contractor assumes certain risks +associated with loss of the well from fire, blowouts, and other +risks. +Turnkey Contracts +Under turnkey contracts, we contract to drill a +well to a certain depth under specified conditions for a fixed +fee. In a turnkey arrangement, we are required to bear the costs +of services, supplies, and equipment beyond those typically +provided under a footage contract. In addition to the drilling +rig and crew, we are required to provide the drilling and +completion fluids, casing, cementing, and the technical well +design and engineering services during the drilling process. We +also assume certain risks associated with drilling the well such +as fires, blowouts, cratering of the well bore, and other such +risks. Compensation occurs only when the agreed scope of the +work has been completed which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract we +have the opportunity to improve our margins 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, margins can be significantly reduced and +losses incurred if complications or delays occur during the +drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts: daywork, footage, and turnkey. +The following table sets forth the approximate +percentage of our drilling revenues attributable to daywork, +footage, and turnkey contracts for each of the last three years: +Years Ended December 31, +Type of Revenues +2003 +2002 +2001 +Daywork +83 +% +82 +% +93 +% +Footage +7 +11 +3 +Turnkey +10 +7 +4 +Contract Drilling +Activity — The following +table sets forth certain information regarding our contract +drilling activity for each of the last three years: +Years Ended December 31, +2003 +2002 +2001 +Average rigs owned +336 +323 +302 +Average rigs operating(1) +188 +126 +211 +Average rig utilization rate +56 +% +39 +% +70 +% +Number of rigs operated +226 +230 +287 +Number of wells drilled +3,017 +2,012 +2,869 +(1) +A rig is operating when it is drilling, being +moved, assembled, or dismantled under contract. +4 +Table of Contents +Drilling Rigs and Related +Equipment — The following +table provides certain information about our drilling rigs as of +December 31, 2003: +Depth Rating (ft.) +Mechanical +Electric +4,000 to 9,999 +60 +— +10,000 to 11,999 +68 +2 +12,000 to 14,999 +119 +6 +15,000 to 30,000 +57 +31 +Totals +304 +39 +At December 31, 2003, we owned +261 trucks and 316 trailers used to rig down, +transport, and rig up our drilling rigs. This reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig +equipment is performed at our yard facilities located in Texas, +New Mexico, Oklahoma, and Western Canada. +Pressure Pumping Operations +General — +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. Pressure pumping +services consist primarily of well stimulation and cementing for +the completion of new wells and remedial work on existing wells. +Most wells drilled in the Appalachian Basin require some form of +fracturing or other stimulation to enhance the flow of oil and +natural gas which is accomplished by pumping fluids under +pressure into the well bore. Generally, Appalachian Basin wells +require cementing services before production commences. +Cementing is the process of inserting material between the wall +of the well bore and the casing to center and stabilize the +casing. +Equipment — +As of December 31, 2003, we operated the following pressure +pumping equipment: +• +21 cement pumper trucks, +• +24 fracturing pumper trucks, +• +20 nitrogen pumper trucks, +• +11 blender trucks, +• +11 bulk acid trucks, +• +25 bulk cement trucks, +• +6 bulk nitrogen trucks, +• +31 bulk sand trucks, and +• +11 connection trucks. +Drilling and Completion Fluids +Operations +General — +We provide drilling fluids, completion fluids, and related +services to oil and natural gas operators in West Texas, +Southeast New Mexico, South Texas, East Texas, Oklahoma, the +Gulf Coast regions of Texas and Louisiana, and the Gulf of +Mexico. We serve our offshore customers through seven +stockpoints located along the Gulf of Mexico in Texas and +Louisiana and our land-based customers through seven stockpoints +in Texas, Louisiana, Oklahoma, and New Mexico. +Drilling +Fluids — Drilling fluid +products and systems are used to cool and lubricate the bit +during drilling operations, contain formation pressures (thereby +minimizing blowout risk), suspend and remove rock cuttings from +the hole, and maintain the stability of the wellbore. Technical +services are provided to ensure that the products and systems +are applied effectively to optimize drilling operations. +5 +Table of Contents +Completion +Fluids — After a well is +drilled it undergoes the completion process wherein the well +casing is set and cemented into place. At that point, the +drilling fluid services are complete, and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used by operators to control bottom-hole pressures +and to meet a well’s specific corrosion, inhibition, +viscosity, and fluid loss requirements during the completion and +workover phases. +Raw +Materials — Our drilling and +completion fluids operations depend on the availability of the +following raw materials: +Drilling +Completion +barite +calcium chloride +bentonite +calcium bromide +zinc bromide +We obtain these raw materials through purchases +made on the spot market and supply contracts with producers of +these raw materials. +Barite Grinding +Facility — We own and +operate a barite grinding facility equipped with two barite +grinding mills located in Houma, Louisiana. This facility allows +us to grind raw barite into the powder additive used in drilling +fluids. We believe the ability to process our own barite is +critical to being competitive on the Gulf Coast and in the Gulf +of Mexico. +Other +Equipment — We own +20 trucks and 75 trailers and lease another 22 trucks +which are used to transport drilling and completion fluids and +related equipment. +Oil and Natural Gas Operations +General — +We are engaged in the development, exploration, acquisition, and +production of oil and natural gas. Our oil and natural gas +business operates primarily in producing regions of West Texas, +Southeast New Mexico, South Texas, and Mississippi. Our strategy +for our oil and natural gas operations is to increase our +reserve base primarily through developmental drilling, as well +as selected acquisitions of leasehold acreage and producing +properties. +Oil and Natural Gas +Reserves — The following +table sets forth estimates, derived from reserve reports +provided by M. Brian Wallace, an independent petroleum engineer, +of our proved developed reserves and estimated future net +revenues from our proved developed reserves as of +December 31, 2003, 2002, and 2001. The estimates were based +upon production histories, current market prices for oil and +natural gas, and other geologic, ownership, and engineering data +provided by us. The present values (discounted at 10% before +income taxes) of estimated future net revenues shown in the +table are not intended to represent the current market value of +the estimated oil and natural gas reserves. For further +information concerning the present value of estimated future net +revenues from these proved developed reserves, see also +Note 20 of Notes to Consolidated Financial Statements +included as a part of Item 8 of this Report. +Proved oil and natural gas reserves are the +estimated quantities of oil and natural gas which geological and +engineering data demonstrate, with reasonable certainty, to be +recoverable in future years from known reservoirs under existing +economic and operating conditions. Reserves are considered +proved if economical productibility is supported by either +actual production or conclusive formation tests. Proved +developed oil and +6 +Table of Contents +natural gas reserves can be expected to be +recovered through existing wells with existing equipment and +operating methods. +As of December 31, +2003 +2002 +2001 +(In thousands) +Proved Developed Reserves: +Oil (Bbls) +1,147 +1,227 +1,047 +Gas (Mcf) +5,267 +6,240 +4,634 +Total (BOE) +2,025 +2,267 +1,819 +Estimated future net revenues before income taxes +$ +47,873 +$ +46,016 +$ +19,597 +Present value of estimated future net revenues +before income taxes, discounted at 10% +$ +34,371 +$ +32,308 +$ +14,492 +Standardized measure of discounted future net +cash flows(1) +$ +23,950 +$ +21,100 +$ +10,714 +(1) +For the calculation of standardized measure of +discounted future net cash flows, see Note 20 of Notes to +Consolidated Financial Statements included as a part of +Item 8 of this Report. +A barrel (Bbl) of oil is 42 U.S. gallons and +represents the basic unit for measuring production of crude oil +and condensate. +An Mcf of natural gas refers to a volume of 1,000 +cubic feet under prescribed conditions of pressure and +temperature and represents the basic unit for measuring volumes +of produced natural gas. A barrel of equivalent (BOE) in +reference to natural gas equivalents is determined using the +rate of six Mcf of natural gas to one Bbl of crude oil or +condensate. +Production — +At December 31, 2003, we held a working interest in +315 productive wells, of which 150 were considered oil and +165 were considered natural gas. A productive well is a well +producing oil or natural gas in commercial quantities. A working +interest is the operating interest under an oil or natural gas +lease which gives the owner the right to explore for and produce +oil or natural gas from the lease. We were the operator of 172 +of these wells at December 31, 2003. The following table +sets forth our net oil and natural gas production, average sales +price, and average production costs. Production costs are costs +incurred to operate and maintain our wells and related equipment +and include costs of labor, well service and repair, utilities, +field supervision, property taxes, production, and severance +taxes and related charges. +Years ended December 31, +2003 +2002 +2001 +Average net daily production: +Oil (Bbls) +788 +794 +739 +Gas (Mcf) +5,656 +5,109 +4,654 +Total (BOE) +1,731 +1,646 +1,515 +Average sales prices: +Oil (per Bbl) +$ +30.54 +$ +25.02 +$ +24.88 +Gas (per Mcf) +4.97 +2.91 +4.12 +Average production costs (per BOE) +$ +5.51 +$ +5.11 +$ +5.32 +7 +Table of Contents +Productive +Wells — The following table +sets forth information regarding the number of productive wells +in which we held a working interest as of December 31, +2003. One or more completions in the same well bore are +reflected as one well. +Productive Wells +Gross +Net +Oil +150 +29.49 +Gas +165 +22.22 +Total +315 +51.71 +Developed and Undeveloped +Acreage — The following +table sets forth the developed and undeveloped acreage in which +we owned a working interest at December 31, 2003: +Developed Acreage +Undeveloped Acreage +Location +Gross +Net +Gross +Net +Texas +61,055 +10,758 +45,438 +9,406 +Kansas +320 +45 +— +— +Louisiana +640 +32 +— +— +New York +160 +131 +— +— +New Mexico +7,919 +1,027 +1,881 +301 +Mississippi +2,400 +469 +8,000 +1,760 +Pennsylvania +880 +129 +— +— +Total +73,374 +12,591 +55,319 +11,467 +Undeveloped acreage is leased acres on which +wells have not been drilled to a point that would permit +production of commercial quantities of oil and natural gas. +Developed acreage is leased acres that have been assigned to +productive wells. Our gross acreage is the total number of +acres, developed or undeveloped, in which we own a working +interest, regardless of the size of our working interest in the +acreage. Our net acreage is the gross acreage proportionally +reduced to our working interest in the acreage. +Many of our leases summarized in the table above +as undeveloped acreage will expire at the end of their +respective primary terms unless production has been obtained +from the acreage prior to that date. If production is obtained, +the lease will remain in effect until the cessation of +production. The following table sets forth the gross and net +acreage subject to leases summarized in the table of undeveloped +acreage that will expire: +Lease Acres Expiring +Gross +Net +Years ending: +December 31, 2004 +5,019 +1,339 +December 31, 2005 +2,419 +587 +December 31, 2006 and later +47,881 +9,541 +Total +55,319 +11,467 +8 +Table of Contents +Drilling +Activities — The following +table sets forth the results of our participation in the +drilling of developmental and exploratory wells during 2003, +2002 and 2001: +Developmental Wells +Exploratory Wells +Productive +Dry Holes +Productive +Dry Holes +Years ended December 31, +Gross +Net +Gross +Net +Gross +Net +Gross +Net +2003 +27 +4.58 +11 +2.52 +12 +1.99 +4 +0.88 +2002 +24 +4.17 +11 +2.67 +6 +0.56 +1 +0.25 +2001 +20 +3.82 +5 +1.06 +5 +0.87 +2 +0.56 +Total +71 +12.57 +27 +6.25 +23 +3.42 +7 +1.69 +In addition, we were participating in six wells, +1.33 net, that were being drilled at December 31, 2003. +Generally, a developmental well is a well that is +drilled into an oil and natural gas reservoir that is known to +be productive. An exploratory well is a well that is drilled to +find oil and natural gas in an unproved area. +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 2003, no +single customer accounted for 10% or more of our consolidated +operating revenues. +Competition +Contract Drilling and Pressure Pumping +Businesses — Our land +drilling and pressure pumping businesses are intensely +competitive due to the fact that the supply of available land +drilling rigs and pressure pumping equipment exceeds the demand +for those rigs and 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. +Drilling and Completion Fluids +Business — The drilling and +completion fluids services industry is highly competitive. Price +is generally the most important competitive factor in the +industry. Other competitive factors include the availability of +chemicals and experienced personnel, the reputation of the +fluids services provider in the drilling industry, and our +relationship with customers. Some of our competitors have +substantially greater resources and longer operating histories +than we have. We believe that competition for drilling and +completion fluids service contracts will continue to be intense. +Oil and Natural Gas +Business — There is +substantial competition for the acquisition of oil and natural +gas leases suitable for development and exploration and for the +hiring of 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 financial resources, staffs, and facilities +greater than ours. +9 +Table of Contents +Government and Environmental +Regulation +All of our operations and facilities are subject +to numerous federal, state, foreign, and local laws, rules, and +regulations related to various aspects of our business, +including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, +oilfield waste, other waste materials, and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, we have not been required to expend +significant resources in order to satisfy applicable +environmental laws and regulations. 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 +for noncompliance. +Our business is generally affected by political +developments and by federal, state, foreign, and local laws and +regulations, which relate to the oil and natural gas industry. +The adoption of laws and regulations affecting the oil and +natural gas industry for economic, environmental, and other +policy reasons could increase costs relating to drilling and +production. They could have an adverse effect on our operations. +Several state and federal environmental laws and regulations +currently apply to our operations and may become more stringent +in the future. +We have utilized operating and disposal practices +that were or are currently 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 +operated by us or our predecessors. In addition, some of these +properties have been operated by third parties over whom we have +no control either as to such entities’ treatment of +hydrocarbon and other materials or the manner in which such +materials may have been disposed of or released. +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, as amended, and comparable state statutes govern the +disposal of “hazardous wastes.” Although CERCLA +currently excludes petroleum from the definition of +“hazardous substances,” and the Resource Conservation +and Recovery Act also excludes certain classes of exploration +and production wastes from regulation, such exemptions by +Congress under both CERCLA and the Resource Conservation and +Recovery Act may be deleted, limited, or modified in the future. +If such changes are made to CERCLA and/or the Resource +Conservation and Recovery Act, 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 +10 +Table of Contents +damages. Penalties may also be imposed for +violation of federal safety, construction, and operating +regulations, and for failure to report a spill or to cooperate +fully in a clean-up. +The Oil Pollution Act also expands the authority +and capability of the federal government to direct and manage +oil spill clean-up and operations, and requires operators to +prepare oil spill response plans in cases where it can +reasonably be expected that substantial harm will be done to the +environment by discharges on or into navigable waters. We have +spill prevention control and countermeasure plans in place for +our oil and natural gas properties in each of the areas in which +we operate and for each of the stockpoints operated by our +drilling and completion fluids business. Failure to comply with +ongoing requirements or inadequate cooperation during a spill +event may subject a responsible party, such as Patterson-UTI, 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 +Patterson-UTI. Amendments to the Clean Air Act revised the +definition of “major source” such that emissions from +both wellhead and associated equipment involved in oil and +natural gas production may be added to determine if a source is +a “major source.” As a consequence, more facilities +may become major sources and thus would be required to obtain +operating permits. This permitting process may require capital +expenditures in order to comply with permit limits. +Risks and Insurance +Our operations are subject to the many hazards +inherent in the drilling business, including: +• +accidents at the work location, +• +blow-outs, +• +cratering, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment +involved and, in addition to environmental damage, could cause +substantial damage to producing formations and surrounding areas. +Damage to the environment, including property +contamination in the form of either soil or ground water +contamination, could also result from our operations, +particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability +for reservoir damages. The occurrence of a significant event, +including pollution or environmental damages, could materially +affect our operations and financial condition. +11 +Table of Contents +As a protection against operating hazards, we +maintain insurance coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for +public liability and property damage to others with respect to +our operations. However, such insurance may not be sufficient to +protect us against liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance coverage for major +physical damage to our drilling rigs. However, we do not carry +insurance against loss of earnings resulting from such damage. +In view of the difficulties that may be encountered in renewing +such insurance at reasonable rates, no assurance can be given +that: +• +we will be able to maintain the type and amount +of coverage that we believe to be adequate at reasonable rates, +or +• +any particular types of coverage will be +available. +In addition to insurance coverage, we also +attempt to obtain indemnification from our customers for certain +risks. These indemnity agreements typically require our +customers to hold us harmless in the event of loss of production +or reservoir damage. These contractual indemnifications may not +be supported by adequate insurance maintained by the customer. +Employees +We employed approximately 5,800 full-time persons +(300 office personnel and 5,500 field personnel) at +December 31, 2003. The number of field employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our +overall operations. However, our pressure pumping division in +Appalachia and our drilling operations in Canada are subject to +slow periods of activity during the Spring thaw. In addition, +our drilling operations in Canada are subject to slow periods of +activity during the Fall. +Raw Materials and Subcontractors +Patterson-UTI uses many suppliers of raw +materials and services. These materials and services have been +and continue to be available. We also utilize numerous +independent subcontractors from various trades. +Incorporation by Reference +The various factors disclosed under the caption +“Forward Looking Statements and Cautionary Statement for +Purposes of the ‘Safe Harbor’ Provisions of the +Private Securities Litigation Reform Act of 1995,” +12 +Table of Contents +beginning on page 15 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 Item 1 and 2. +Corporate Headquarters, Field Offices, and +Other Facilities +Our corporate headquarters are located in Snyder, +Texas. We also have a number of offices, yard, 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: +• +an office building with approximately 34,000 +square feet of office space and storage, +• +a shop facility with approximately 7,000 square +feet used for drilling equipment repairs and metal fabrication, +• +a truck shop facility with approximately 10,000 +square feet used to maintain, overhaul and repair our truck +fleet, +• +an engine shop facility with approximately 20,000 +square feet used to overhaul and repair the engines used to +power our drilling rigs, and +• +an open-ended metal storage facility with +approximately 10,200 square feet. +We have regional administrative offices, yard, +and stockpoint facilities in many of the areas in which we +operate. The facilities are primarily used to support the +day-to-day operations, including the repair and maintenance of +equipment as well as the storage of equipment, inventory, and +supplies and to facilitate administrative responsibilities and +sales. +Contract Drilling +Operations — Our drilling +services are supported by several administrative offices and +yard facilities located throughout our areas of operations +including: +• +Texas, +• +New Mexico, +• +Oklahoma, +• +Colorado, +• +Utah, and +• +Western Canada. +Pressure +Pumping — Our pressure +pumping services are supported by several offices and yard +facilities located throughout our areas of operations including: +• +Pennsylvania, +• +Ohio, +• +West Virginia, +• +Kentucky, +• +Wyoming, and +• +Eastern Canada. +13 +Table of Contents +Drilling and Completion +Fluids — Our drilling and +completion fluids services are supported by several +administrative offices and stockpoint facilities located +throughout our areas of operations including: +• +Texas, +• +Louisiana, +• +New Mexico, and +• +Oklahoma. +Oil and Natural +Gas — Our oil and natural +gas services are supported by administrative and field offices +in Texas. +We own our headquarters in Snyder, Texas, and +lease the majority of our other facilities. We do not believe +that any of these other facilities are individually material to +our operations. We believe that our existing facilities are +suitable and adequate to meet our needs. +Item 3. +Legal Proceedings. +Westfort Energy LTD and Westfort Energy +(US) LTD f/k/a Canadian Delta, Inc. (“Westfort”), +filed a lawsuit against two Patterson-UTI subsidiaries, +Patterson Petroleum LP, and Patterson-UTI Drilling Company LP, +in the Circuit Court, Rankin County, Mississippi, Case +No. 2002-18. The lawsuit relates to a letter agreement +entered into in July 2000 between Patterson Petroleum LP and +Westfort concerning the drilling of a daywork well in +Mississippi. This lawsuit was filed by Westfort after Patterson +Petroleum LP made demand on Westfort for payment of the contract +drilling services. +The Westfort lawsuit has been dismissed without +prejudice. Westfort filed for bankruptcy in May of 2003. We +continue to assert claims against Westfort including the monies +owed Patterson Petroleum LP under the letter agreement in the +amount of approximately $5,075,000. Amounts deemed uncollectible +have been reserved. We believe that it is remote that the +outcome of this matter will have a material adverse effect on +Patterson-UTI’s financial condition and results of +operations. +In this lawsuit, Westfort alleged breach of +contract, fraud, and negligence causes of action. Westfort +sought alleged monetary damages, the return of shares of +Westfort stock, unspecified damages from alleged lost profits, +lost use of income stream, and additional operating expenses, +along with alleged punitive damages to be determined by the +jury, but not less than 25% of Patterson-UTI’s net worth. +We intend to vigorously contest these claims if reasserted by +Westfort. +We are also party to various legal proceedings +arising in the normal course of our business. We do not believe +that the outcome of these proceedings, either individually or in +the aggregate, will have a material adverse effect on our +financial condition. +Item 4. +Submission of Matters to a Vote of Security +Holders. +None. +14 +Table of Contents +FORWARD LOOKING STATEMENTS AND +CAUTIONARY +STATEMENTS FOR PURPOSES OF THE “SAFE +HARBOR” PROVISIONS +OF THE PRIVATE SECURITIES LITIGATION REFORM +ACT OF 1995 +Patterson-UTI from time to time makes written or +oral forward-looking statements, including statements contained +in this Annual Report on Form 10-K, our other filings with +the SEC, press releases, and reports to stockholders. These +forward-looking statements are made pursuant to the “safe +harbor” provisions of the Private Securities Litigation +Reform Act of 1995. These statements include, without +limitation, statements relating to liquidity, financing of +operations, sources and sufficiency of funds, and impact of +inflation. The words “believes,” “budgeted,” +“expects,” “project,” “will,” +“could,” “may,” “plans,” +“intends,” “strategy,” or +“anticipates,” and similar expressions are used to +identify our forward-looking statements. We do not undertake to +update, revise, or correct any of our forward-looking +information. +We include the following cautionary statement in +accordance with the “safe harbor” provisions of the +Private Securities Litigation Reform Act of 1995 for any +forward-looking statement made by us, or on our behalf. The +factors identified in this cautionary statement are important +factors (but not necessarily all of the important factors) that +could cause actual results to differ materially from those +expressed in any forward-looking statement made by us, or on our +behalf. Where any such forward-looking statement includes a +statement of the assumptions or bases underlying such +forward-looking statement, we caution that, while we believe +such assumptions or bases to be reasonable and make them in good +faith, assumed facts or bases almost always vary from actual +results. The differences between assumed facts or bases and +actual results can be material, depending upon the circumstances. +Where, in any forward-looking statement, +Patterson-UTI, or our management, expresses an expectation or +belief as to the future results, such expectation or belief is +expressed in good faith and believed to have a reasonable basis. +However, there can be no assurance that the statement of +expectation or belief will result, or be achieved or +accomplished. Taking this into account, the following are +identified as important risk factors currently applicable to, or +which could readily be applicable to, Patterson-UTI: +Patterson-UTI is Dependent on the Oil and +Natural Gas Industry and Market Prices for Oil and Natural Gas. +Declines in Oil and Natural Gas Prices Have Adversely Affected +Our Operations. +Our revenue, profitability, and rate of growth +are substantially dependent upon prevailing prices for oil and +natural gas. In recent years, oil and natural gas prices and, +therefore, the level of drilling, exploration, development, and +production, have been extremely volatile. Prices are affected by: +• +market supply and demand, +• +international military, political, and economic +conditions, and +• +the ability of the Organization of Petroleum +Exporting Countries, commonly known as OPEC, to set and maintain +production and price targets. +All of these factors are beyond our control. +Natural gas prices fell from an average of $6.23 per Mcf in the +first quarter of 2001 to an average of $2.51 per Mcf for the +same period in 2002. During this same period, the average number +of our rigs operating dropped by approximately 50%. The average +market price of natural gas improved to $5.45 in 2003 compared +to $3.36 in 2002, resulting in an increase in demand for our +drilling services. Our average number of rigs operating +increased to 188 in 2003 from 126 in 2002. We expect oil and +natural gas prices to continue to be volatile and to affect our +financial condition and operations and ability to access sources +of capital. +A General Excess of Operable Land Drilling +Rigs Adversely Affects Our Profit Margins Particularly in Times +of Weaker Demand. +The contract drilling business experienced +increased demand for drilling services in 1997, 2000 and 2001. +However, except for those periods and other occasional upturns, +generally, there have been substantially more drilling rigs +available than necessary to meet demand in most operational and +geographic segments of the +15 +Table of Contents +North American land drilling industry. As a +result, drilling contractors have had difficulty sustaining +profit margins. +In addition to adverse effects that future +declines in demand could have on Patterson-UTI, ongoing factors +which could adversely affect utilization rates and pricing, even +in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +new construction of drilling rigs. +We cannot predict either the future level of +demand for our contract drilling services or future conditions +in the oil and natural gas contract drilling business. +Shortages of Drill Pipe, Replacement Parts, +and Other Related Rig Equipment Adversely Affects +Patterson-UTI’s Operating Results. +During periods of increased demand for drilling +services, the industry has experienced shortages of drill pipe, +replacement parts, and other related rig equipment. These +shortages can cause the price of these items to increase +significantly and require that orders for the items be placed +well in advance of expected use. These price increases and +delays in delivery may require us to substantially increase +capital expenditures in our contract drilling segment. Severe +shortages could impair our ability to operate our drilling rigs. +The Various Business Segments in Which We +Operate Are Highly Competitive with Excess Capacity which may +Adversely Affect Our Operating Results. +Our land drilling and pressure pumping businesses +are intensely competitive due to the fact that the supply of +available land drilling rigs and pressure pumping equipment +exceeds the demand for those rigs and 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. +Patterson-UTI believes that price competition for +drilling and pressure pumping contracts will continue for the +foreseeable future due to the existence of available rigs and +pressure pumping equipment. +In recent years, many drilling and pressure +pumping companies have consolidated or merged with other +companies. Although this consolidation has decreased the total +number of competitors, we believe the competition for drilling +and pressure pumping services will continue to be intense. +The drilling and completion fluids services +industry is highly competitive. Price is generally the most +important competitive factor in the industry. Other competitive +factors include the availability of chemicals and experienced +personnel, the reputation of the fluids services provider in the +drilling industry, and our relationship with existing customers. +Some of our competitors have substantially greater resources and +longer operating histories than we have. We believe that +competition for our drilling and completion fluids service +contracts will continue to be intense. +Labor Shortages Adversely Affect Our Operating +Results. +During periods of increased demand for contract +drilling services, the industry experiences shortages of +qualified drilling rig personnel. During these periods, our +ability to attract and retain sufficient qualified personnel to +market and operate our drilling rigs is adversely affected which +in turn has a negative impact on both our operations and +profitability. Operationally, it is more difficult to hire +qualified personnel which adversely affects our ability to +mobilize inactive rigs in response to the increased demand for +our contract drilling services. Additionally, wage rates for +drilling personnel are likely to increase, resulting in greater +operating costs. During the last upturn in our industry, we +experienced an approximate 30% to 40% increase in wage rates to +our drilling personnel. +16 +Table of Contents +Continued Growth of Patterson-UTI Through Rig +Acquisition is Not Assured. +We have increased our drilling rig fleet over the +past several years through mergers and acquisitions. The land +drilling industry has experienced significant consolidation over +the past several years, and there can be no 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 would: +• +have sufficient capital resources to complete +additional acquisitions, +• +successfully integrate acquired operations and +assets, +• +be able to manage effectively the growth and +increased size, +• +be successful in deploying idle or stacked rigs, +• +be able to maintain the crews and market share +attributable to operating drilling rigs acquired, or +• +be successful in improving our financial +condition, results of operations, business, or prospects in any +material manner as a result of any completed acquisition. +We may incur substantial indebtedness to finance +future acquisitions and also may issue equity securities or +convertible securities in connection with any such acquisitions. +Debt service requirements could represent a significant burden +on our results of operations and financial condition and the +issuance of additional equity could be dilutive to our existing +stockholders. Also, continued growth could strain our +management, operations, employees, and resources. +The Nature of our Business Operations Presents +Inherent Risks of Loss that, if not Insured or Indemnified +Against, Could Adversely Affect Patterson-UTI’s Operating +Results. +Our operations are subject to many hazards +inherent in the contract drilling, pressure pumping, and +drilling and completion fluids businesses, which in turn could +cause personal injury or death, work stoppage, or serious damage +to our equipment. Our operations could also cause environmental +and reservoir damages. We maintain insurance coverage and have +indemnification agreements with many of our customers. However, +there is no assurance that such insurance or indemnification +agreements would adequately protect Patterson-UTI against +liability or losses from all consequences of the hazards. +Additionally, there can be no assurance that insurance would be +available to cover any or all of these risks, or, even if +available, that insurance premiums or other costs would not rise +significantly in the future, so as to make such insurance +prohibitive. +We have elected in some cases to accept a greater +amount of risk through increased deductibles on certain +insurance policies. For example, we maintain a $750,000 per +occurrence deductible on our workers’ compensation +insurance coverage and a $1.0 million per occurrence +deductible on our general liability insurance coverage. These +levels of self-insurance expose us to increased operating costs +and risks. +Violations of Environmental Laws and +Regulations Could Materially Adversely Affect +Patterson-UTI’s 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 to Patterson-UTI of compliance +with these laws and regulations could be substantial. Failure to +comply with these requirements could subject Patterson-UTI 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. Patterson-UTI, as an +owner and operator of land-based drilling rigs, may be deemed to +be a responsible party under federal law. Our operations and +facilities are subject to numerous state and federal +environmental laws, rules, and regulations, including, without +limitation, laws concerning the containment, and disposal of +hazardous substances, oil field waste and other waste materials, +the use of underground storage tanks, and the use of underground +injection wells. +17 +Table of Contents +Some of Our Contract Drilling Services are +Done Under Turnkey and Footage Contracts, Which are Financially +Risky. +A portion of our contract drilling is done under +turnkey and footage contracts, which involve significant risks. +Under turnkey drilling contracts, we contract to drill a well to +a certain depth under specified conditions for a fixed price. +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions at a fixed price per +foot. The risk to us under these types of drilling contracts are +greater than on a well drilled on a daywork basis. Unlike +daywork contracts, we must bear the cost of performing drilling +services until the target depth is reached. We must also make +significant up-front working capital commitments prior to +receiving payment. In addition, we must assume most of the risk +associated with the drilling operations, generally assumed by +the operator of the well on a daywork contract, including +blowouts, loss of hole from fire, machinery breakdowns, and +abnormal drilling conditions. Accordingly, if severe drilling +problems are encountered in drilling wells under such contracts, +we could suffer substantial losses. +Anti-takeover Measures in Our Charter +Documents and Under State Law Could Discourage an Acquisition of +Patterson-UTI and Thereby Affect the Related Purchase +Price. +Patterson-UTI, as a Delaware corporation, is +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 of Patterson-UTI may find it more difficult +or be discouraged from attempting to effect an acquisition +transaction with us. This may deprive holders of our securities +of certain opportunities to sell or otherwise dispose of the +securities at above-market prices pursuant to any such +transactions. +We have Paid no Dividends on Our Common Stock +and have no Plans to Pay Dividends. +We have not declared or paid cash dividends on +our common shares in the past. We currently have no plan to +declare or pay any cash dividends on our common stock in the +foreseeable future. The terms of our existing credit facility +limit payment of dividends without the prior written consent of +the lenders. +PART II +Item 5. +Market for Registrant’s Common Equity +and Related Stockholder Matters. +Our common stock, par value $0.01 per share, is +publicly traded on the Nasdaq National Market and is quoted +under the symbol “PTEN.” In December 2002, our common +stock was added to the Nasdaq-100 Index and in November 2001, +our common stock was added to the S&P MidCap 400 Index. Our +common stock is also included in several other market indexes. +18 +Table of Contents +The following table sets forth the high and low +sales prices of our common shares for the periods indicated: +High +Low +2003: +First quarter +$ +35.50 +$ +27.09 +Second quarter +36.97 +31.80 +Third quarter +32.28 +25.15 +Fourth quarter +33.93 +25.67 +2002: +First quarter +$ +29.85 +$ +18.87 +Second quarter +34.60 +26.83 +Third quarter +29.78 +20.63 +Fourth quarter +33.97 +23.96 +As of December 31, 2003, there were +approximately 300 holders of record and approximately 19,000 +beneficial holders of our common shares. +We have not declared or paid cash dividends on +our common shares in the past. We currently have no plan to +declare or pay any cash dividends on our common stock in the +foreseeable future. Instead, we currently intend to retain our +earnings to support the operations and growth of our business. +Any future cash dividends would depend on future earnings, +capital requirements, financial condition, and other factors +deemed relevant by the Board of Directors. In addition, the +terms of our existing credit facility limit payment of dividends +without the prior written consent of the lenders. +The following table summarizes as of +December 31, 2003, certain information regarding equity +compensation to our employees, officers, directors, and other +persons under our equity compensation plans: +Equity Compensation Plan Information +Number of +Number of +securities +securities to +Weighted- +remaining available +be issued upon +average exercise +for future issuance +exercise of +price of +under equity +outstanding +outstanding +compensation plans +options, +options, +(excluding +warrants and +warrants and +securities reflected +Plan category +rights +rights +in column (a)) +(a) +(b) +(c) +Equity compensation plans approved by security +holders +5,279,021 +$ +20.82 +2,242,037 +Equity compensation plans not approved by +security holders(1) +858,737 +$ +19.39 +25,694 +Total +6,137,758 +$ +20.62 +2,267,731 +(1) +The Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan was approved by the Company’s Board of +Directors in July 2001. The terms of the Plan provide for grants +of stock options to eligible employees other than officers and +directors of the Company. The total number of stock options that +could be granted under the Plan was 1,000,000. No Incentive +Stock Options may be awarded under the Plan. All options are +granted with an exercise price equal to or greater than the fair +market value of the Company’s common stock at the time of +grant. The vesting schedule and term are set by the Compensation +Committee of the Board of Directors. +Also in July 2001, the Company’s Board of +Directors approved option grants, not included in any of the +Company’s stock option plans, for two non-employee +directors, each covering options to purchase 12,000 shares of +the Company’s common stock at an exercise price greater +than the fair market value of the +19 +Table of Contents +Company’s common stock on the grant date. +The options vested in November 2001 and expire in November 2005. +Item 6. +Selected Financial Data. +The selected consolidated financial data of +Patterson-UTI as of December 31, 2003, 2002, 2001, 2000, +and 1999, and for each of the five years then ended should be +read in conjunction with “Management’s Discussion and +Analysis of Financial Condition and Results of Operations” +and the Consolidated Financial Statements and related Notes +thereto, included as Items 7 and 8, respectively, of this +Report. Historical financial statements as presented herein, +have been restated to provide for the retroactive effect of the +merger with UTI Energy Corp., on May 8, 2001. +Years Ended December 31, +2003 +2002 +2001 +2000 +1999 +(In thousands, except per share amounts) +Income Statement Data: +Operating revenues: +Drilling +$ +639,694 +$ +410,295 +$ +839,931 +$ +512,998 +$ +266,212 +Pressure pumping +46,083 +32,996 +39,600 +21,465 +20,721 +Drilling and completion fluids +69,230 +69,943 +94,456 +32,053 +11,686 +Oil and natural gas +21,163 +14,723 +15,988 +15,806 +8,563 +Other +— +— +— +— +184 +Total +776,170 +527,957 +989,975 +582,322 +307,366 +Operating costs and expenses: +Drilling +475,224 +318,201 +487,343 +384,840 +224,590 +Pressure pumping +26,184 +19,802 +21,146 +13,403 +12,219 +Drilling and completion fluids +61,424 +60,762 +80,034 +26,545 +9,864 +Oil and natural gas +4,808 +3,956 +5,190 +4,872 +2,500 +Depreciation, depletion, and amortization +97,998 +91,216 +86,159 +61,464 +52,553 +General and administrative +27,709 +26,140 +28,561 +22,190 +17,735 +Bad debt expense +259 +320 +2,045 +570 +282 +Merger costs +— +— +5,943 +— +— +Restructuring and other charges +(2,452 +) +4,700 +7,202 +— +— +Other +(2,174 +) +(538 +) +(820 +) +(147 +) +(2,927 +) +Total +688,980 +524,559 +722,803 +513,737 +316,816 +Operating income (loss) +87,190 +3,398 +267,172 +68,585 +(9,450 +) +Other income (expense) +967 +441 +(677 +) +(8,481 +) +(7,053 +) +Income (loss) before income taxes and +cumulative effect of change in accounting principle +88,157 +3,839 +266,495 +60,104 +(16,503 +) +Income tax expense (benefit) +32,362 +1,670 +102,333 +22,878 +(4,766 +) +Income (loss) before cumulative effect of +change in accounting principle +55,795 +2,169 +164,162 +37,226 +(11,737 +) +20 +Table of Contents +Years Ended December 31, +2003 +2002 +2001 +2000 +1999 +(In thousands, except per share amounts) +Cumulative effect of change in accounting +principle, net of related income tax benefit of approximately +$287. +(469 +) +— +— +— +— +Net income (loss) +$ +55,326 +$ +2,169 +$ +164,162 +$ +37,226 +$ +(11,737 +) +Net income (loss) per common share: +Basic: +Income (loss) before cumulative effect of +change in accounting principle +$ +0.69 +$ +0.03 +$ +2.15 +$ +0.52 +$ +(0.18 +) +Cumulative effect of change in accounting +principle +(0.01 +) +— +— +— +— +Net income (loss) +$ +0.68 +$ +0.03 +$ +2.15 +$ +0.52 +$ +(0.18 +) +Diluted: +Income (loss) before cumulative effect of +change in accounting principle +$ +0.68 +$ +0.03 +$ +2.07 +$ +0.50 +$ +(0.18 +) +Cumulative effect of change in accounting +principle +(0.01 +) +— +— +— +— +Net income (loss) +$ +0.67 +$ +0.03 +$ +2.07 +$ +0.50 +$ +(0.18 +) +Weighted average number of common shares +outstanding: +Basic +80,636 +78,705 +76,407 +71,207 +66,483 +Diluted +82,286 +81,252 +79,197 +74,841 +66,483 +Balance Sheet Data: +Current assets +$ +308,060 +$ +243,015 +$ +199,458 +$ +237,742 +$ +106,091 +Total assets +1,075,830 +942,509 +869,642 +739,898 +496,715 +Current liabilities +108,447 +75,152 +89,286 +110,443 +60,930 +Long-term debt +— +— +— +79,416 +82,196 +Stockholders’ equity +820,071 +737,556 +687,142 +481,299 +309,695 +Working capital +199,613 +167,863 +110,172 +127,299 +45,161 +Item 7. Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +This Item 7 contains forward-looking +statements, which are made pursuant to the “safe +harbor” provisions of the Private Securities Litigation +Reform Act of 1995. +Management +Overview — We are a leading +provider of contract services to the North American oil and +natural gas industry. Our services primarily involve the +drilling, on a contract basis, of land-based oil and natural gas +wells and to a lesser extent, we provide pressure pumping +services and drilling and completion fluid services. In addition +to the aforementioned contract services, we also engage in the +development, exploration, +21 +Table of Contents +acquisition and production of oil and natural +gas. For the three years ended December 31, 2003 our +operating revenues consisted of the following (dollars in +thousands): +2003 +2002 +2001 +Contract drilling +$ +639,694 +82 +% +$ +410,295 +78 +% +$ +839,931 +85 +% +Pressure pumping +46,083 +6 +32,996 +6 +39,600 +4 +Drilling and completion fluids +69,230 +9 +69,943 +13 +94,456 +9 +Oil and natural gas +21,163 +3 +14,723 +3 +15,988 +2 +$ +776,170 +100 +% +$ +527,957 +100 +% +$ +989,975 +100 +% +We provide our contract services to oil and +natural gas operators throughout 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 and +Western Canada while our pressure pumping services are focused +primarily in the Appalachian Basin. Our drilling and completion +fluids services are provided to operators in Texas, New Mexico, +Oklahoma, the Gulf Coast regions of Texas and Louisiana and the +Gulf of Mexico. Our oil and natural gas operations are primarily +focused in Texas, New Mexico and Mississippi. +We have been a leading consolidator of the +land-based contract drilling industry over the past several +years increasing our drilling fleet to 343 rigs, which we +believe is the second largest drilling fleet in North America. +Our most significant transaction occurred in May 2001 when we +merged with UTI Energy Corp. in a merger of equals which +basically doubled our drilling fleet and added the pressure +pumping services business. Growth by acquisition has been a +corporate strategy intended to expand both revenues and market +share. +The profitability of our business is most readily +assessed by two primary indicators: our average number of rigs +operating and our average revenue per operating day. During +2003, our average number of rigs operating increased to 188 from +126 in 2002 and our average revenue per operating day increased +to $9,300 from $8,930 in 2002. Primarily due to these improved +operating results, we experienced an increase of approximately +$53 million in net income in 2003. +Our revenues, profitability and cash flows are +highly dependent upon the market prices of oil and natural gas. +During periods of improved commodity prices, the capital +spending budgets of oil and natural gas operators tend to +expand, which results in increased demand for our contract +services. Conversely, in periods of time when these commodity +prices deteriorate, the demand for our contract services +generally weakens and we experience downward pressure on pricing +for our services. In addition, our operations are also highly +impacted by competition, the availability of excess equipment, +labor issues and various other factors which are more fully +described as risk factors in our “Forward Looking +Statements and Cautionary Statements for Purposes of the +‘Safe Harbor’ Provisions of the Private Securities +Litigation Reform Act of 1995” contained on page 15 of +this Report. +Management believes that the liquidity of our +balance sheet as of December 31, 2003, which includes +approximately $200 million in working capital (including +$100 million in cash), no long term debt and a $100 million +undrawn line of credit, provides us with the ability to pursue +acquisition opportunities, expand into new regions, make +improvements to our assets and to survive downturns in our +industry. +Commitments and +Contingencies — We have no +commitments or contingencies which require disclosure in our +financial statements other than letters of credit totaling +$37.0 million at December 31, 2003, maintained for the +benefit of various insurance companies as collateral for +retrospective premiums and retained losses which may become +payable under the terms of the underlying insurance contracts. +No amounts have been drawn under the letters of credit. +Net income for the year ended December 31, +2002 includes a charge of $4.7 million related to the +financial failure in 2002 of a workers’ compensation +insurance carrier that had provided coverage for us in prior +years. +22 +Table of Contents +Trading and +investing — We have not +engaged in trading activities that include high-risk securities, +such as derivatives and non-exchange traded contracts. We invest +cash primarily in highly liquid, short-term investments such as +overnight deposits, money markets, and highly rated municipal +and commercial bonds. However in June 2002 and October 2002, we +acquired a total of 1,058,673 shares of common stock of +TMBR/Sharp Drilling, Inc., a company whose stock is traded on +the NASDAQ National Market System, for a total cost of +$17.7 million. +Description of +business — Based on publicly +available information, we believe we are the second largest +owner of land-based drilling rigs in North America. We conduct +our contract drilling operations in Texas, New Mexico, Oklahoma, +Louisiana, Mississippi, Colorado, Utah, Wyoming, and Western +Canada. As of December 31, 2003, we owned 343 drilling +rigs. We provide pressure pumping services to oil and natural +gas operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids, and related services +to oil and natural gas operators in West Texas, Southeast New +Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast +regions of Texas and Louisiana, and the Gulf of Mexico. Drilling +and completion fluids are used by oil and natural gas operators +during the drilling process to control pressure when drilling +oil and natural gas wells. We are also engaged in the +development, exploration, acquisition, and production of oil and +natural gas. Our oil and natural gas business operates primarily +in producing regions in West Texas, Southeast New Mexico, South +Texas and Mississippi. +The contract drilling business experienced +increased demand for drilling services in 1997, 2000 and 2001. +However, except for those periods and other occasional upturns, +generally, there have been substantially more drilling rigs +available than necessary to meet demand in most operational and +geographic segments of the North American land drilling +industry. As a result, drilling contractors have had difficulty +sustaining profit margins. +In addition to adverse effects that future +declines in demand could have on Patterson-UTI, ongoing factors +which could adversely affect utilization rates and pricing, even +in an environment of stronger oil and natural gas prices and +increased drilling activity, include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +new construction of drilling rigs. +We cannot predict either the future level of +demand for our contract drilling services or future conditions +in the oil and natural gas contract drilling business. +Critical Accounting Policies +In addition to established accounting policies, +our consolidated financial statements are impacted by certain +estimates and assumptions made by management. The following is a +discussion of our critical accounting policies pertaining to +property and equipment, oil and natural gas properties, +intangible assets, revenue recognition, and the use of estimates. +Property and +equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our +assets, including intangible assets, for impairment when events +or changes in circumstances indicate that the carrying values of +certain assets either exceed their respective fair values or may +not be recovered over their estimated remaining useful lives. +The cyclical nature of our industry has resulted in fluctuations +in rig utilization over periods of time. Management believes +that the contract drilling industry will continue to be cyclical +and rig utilization will fluctuate. Based on management’s +expectations of future trends, we estimate future cash flows in +our assessment of impairment assuming the +23 +Table of Contents +following four-year industry cycle: one year +projected with low utilization, one year projected as a recovery +period with improving utilization and the remaining two years +projecting higher utilization. Provisions for asset impairment +are charged to income when estimated future cash flows, on an +undiscounted basis, are less than the asset’s net book +value. Impairment charges are recorded based on discounted cash +flows. There were no impairment charges during the years 2003, +2002 or 2001. +Oil and natural gas +properties — Oil and natural +gas properties are accounted for using the successful efforts +method of accounting. Exploration and development costs which +result directly in the discovery of oil and natural gas reserves +are capitalized to the appropriate well. Exploration costs which +do not result directly in the discovery of oil and natural gas +reserves are charged to expense when such determinations are +made. In accordance with Statement of Financial Accounting +Standards No. 19, “Financial Accounting and Reporting +by Oil and Gas Producing Companies,” (“SFAS +No. 19”) costs of exploratory wells are initially +capitalized to wells in progress until the outcome of the +drilling is known. We review wells in progress quarterly to +determine the related reserve classification. If the reserve +classification is uncertain after one year following the +completion of drilling, we consider the costs of the well to be +impaired and recognize the costs as expense. Geological and +geophysical costs, including seismic costs, and costs to carry +and retain undeveloped properties are charged to expense when +incurred. Capitalized costs of both developmental and successful +exploratory type wells, consisting of lease and well equipment, +lease acquisition costs, and intangible development costs, are +depreciated, depleted, and amortized on the units-of-production +method, based on petroleum engineer estimates of proved oil and +natural gas reserves of each respective field. We review our +proved oil and natural gas properties for impairment when an +event occurs such as downward revisions in reserve estimates or +decreases in oil and natural gas prices. Proved properties are +grouped by field and undiscounted cash flow estimates are +provided by our reserve engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment +expense is measured and recognized as the difference between its +net book value and discounted cash flow. Unproved oil and +natural gas properties are reviewed quarterly to determine +impairment. Our intent to drill, lease expiration, and +abandonment of area are considered. Assessment of impairment is +made on a lease-by-lease basis. If an unproved property is +determined to be impaired, then costs related to that property +are expensed. Impairment expense of approximately +$1.4 million, $700,000 and $1.1 million for the years +ended December 31, 2003, 2002 and 2001, respectively, is +included in depreciation, depletion, and amortization in the +accompanying financial statements. +Intangible +assets — Intangible assets +consist primarily of goodwill arising from business combinations +(see Note 5 of Notes to Consolidated Financial Statements +included as part of Item 8 of this Report). Intangible +assets other than goodwill are amortized on a straight line +basis over their estimated useful lives. Covenants not to +compete are amortized over their underlying contractual lives of +five years. Prior to 2002, goodwill, representing the excess of +the purchase price over the estimated fair value of the net +assets of the acquired business, was amortized over the period +of expected benefit of 15 years. However, effective +January 1, 2002, we adopted Statement of Financial +Accounting Standards No. 142, “Goodwill and Other +Intangible Assets,” (“SFAS No. 142”) which +requires that we cease amortization of all intangible assets +having indefinite useful economic lives. Such assets, including +goodwill, are not to be amortized until their lives are +determined to be finite, however, a recognized intangible asset +with an indefinite useful life should be tested for impairment +annually or on an interim basis if events or circumstances +indicate that the fair value of the asset has decreased below +its carrying value. At December 31, 2003, we evaluated our +goodwill and other intangible assets and determined that fair +value had not decreased below carrying value and no adjustment +to impair goodwill and other intangible assets was necessary in +accordance with SFAS No. 142. With respect to our drilling +and completion fluids business, the determination that no +impairment existed was based on our expectations of improvement +in the results of operations for that business segment. If the +expected improvement in results does not occur, all or part of +the goodwill and other intangible assets of approximately $10 +million associated with that business segment may be determined +to be impaired. +Revenue +recognition — Revenues are +recognized when services are performed, except for revenues +earned under turnkey contract drilling arrangements which are +recognized using the completed contract method of accounting, as +described below. We follow the percentage-of-completion method +of accounting for footage contract drilling arrangements. Under +this method, drilling revenues and costs related to a well in +24 +Table of Contents +progress are recognized proportionately over the +time it takes to drill the well. Percentage-of-completion is +determined based upon the amount of expenses incurred through +the measurement date as compared to total estimated expenses to +be incurred drilling the well. Under the +percentage-of-completion method, management estimates are relied +upon in the determination of the total estimated expenses to be +incurred drilling the well. Due to the nature of turnkey +contract drilling arrangements and risks therein, we follow the +completed contract method of accounting for such arrangements. +Under this method, all drilling advances and costs related to a +well in progress are deferred and recognized as revenues and +expenses in the period the well is completed. Provisions for +losses on incomplete or in-process wells are made when estimated +total costs are expected to exceed estimated total revenues. +Use of +estimates — The preparation +of financial statements in conformity with generally accepted +accounting principles requires management to make certain +estimates and assumptions. These estimates and assumptions +affect the reported amounts of assets and liabilities, the +disclosures of contingent assets and liabilities at the balance +sheet date and the amounts of revenues and expenses recognized +during the reporting period. Actual results could differ from +such estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation, depletion, and amortization, +• +asset impairment, +• +reserves for self-insured levels of insurance +coverages, and +• +fair values of assets and liabilities assumed. +For additional information on our accounting +policies, see Note 1 of Notes to Consolidated Financial +Statements included as a part of Item 8 of this Report. +Related party +transactions — In 2001, we +leased a 1981 Beech King-Air 90 airplane owned by SSI Oil and +Gas, Inc., an entity beneficially owned 50% by Cloyce A. +Talbott, Patterson-UTI’s Chief Executive Officer, and +directly owned 50% by A. Glenn Patterson, Patterson-UTI’s +President/Chief Operating Officer. Under the terms of the lease, +we paid a monthly rental of $9,200, the costs of fuel, +insurance, taxes, and maintenance of the aircraft. Such amounts +totaled approximately $212,000 for the year ended +December 31, 2001. +We operate certain oil and natural gas properties +in which certain of our affiliated persons have participated, +either individually or through entities they control, in the +prospects or properties in which we have an interest. These +participations, which have been on a working interest basis, +have been in prospects or properties originated or acquired by +Patterson-UTI. At December 31, 2003, affiliated persons +were working interest owners in 236 of the 260 wells operated by +Patterson-UTI. Sales of working interests are made by +Patterson-UTI to reduce its economic risk in the properties. +Generally, it is more efficient for Patterson-UTI to sell the +working interests to these affiliated persons than to market +them to unrelated third parties. Sales were made by +Patterson-UTI at its cost, comprised of Patterson-UTI’s +costs of acquiring and preparing the working interests for sale. +These costs were paid by the working interest owners on a pro +rata basis based upon their working interest ownership +percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests +were sold to unaffiliated persons. +The following table sets forth production +revenues and joint interest costs of each of the affiliated +persons during 2003 for all wells operated by Patterson-UTI in +which they have working interests. These amounts do not +necessarily represent their profits or losses from these +interests because the joint interest costs do not include the +parties’ related drilling and leasehold acquisition costs +incurred prior to January 1, 2003. These +25 +Table of Contents +activities resulted in a net receivable from the +affiliated persons of approximately $17,000 at December 31, +2003 and a net payable to the affiliated persons of +approximately $466,000 at December 31, 2002. +Year Ended +December 31, 2003 +Joint +Production +Interest +Name +Revenues(1) +Costs(2) +Cloyce A. Talbott +$ +185,180 +$ +85,244 +Anita Talbott(3) +73,424 +27,514 +Jana Talbott, Executrix to the Estate of Steve +Talbott(3) +2,633 +3,467 +Stan Talbott(3) +8,802 +2,531 +John Evan Talbott Trust(3) +2,880 +1,066 +Lisa Beck and Stacy Talbott(3) +737,445 +503,017 +SSI Oil & Gas, Inc.(4) +240,921 +129,290 +IDC Enterprises, Ltd.(5) +9,558,279 +6,829,996 +SSSL, Ltd.(6)(8) +— +1,177 +Subtotal +10,809,564 +7,583,302 +A. Glenn Patterson +125,283 +45,942 +Glenn Patterson Family Limited Partnership(7)(8) +— +1,181 +Robert Patterson(7) +8,423 +3,348 +Thomas M. Patterson(7) +8,423 +3,348 +Subtotal +142,129 +53,819 +Jonathan D. Nelson, Patterson-UTI’s Chief +Financial Officer +151,912 +265,355 +Total +$ +11,103,605 +$ +7,902,476 +(1) +Revenues for production of oil and natural gas, +net of state severance taxes. +(2) +Includes leasehold costs, tangible equipment +costs, intangible drilling costs, and lease operating expense +billed during that period. All joint interest costs have been +paid on a timely basis. +(3) +Anita Talbott is the wife of Cloyce A. Talbott. +Stan Talbott, Lisa Beck, and Stacy Talbott are +Mr. Talbott’s adult children. Steve Talbott is the +deceased son of Mr. Talbott. John Evan Talbott is +Mr. Talbott’s grandson. +(4) +SSI Oil & Gas, Inc. is beneficially +owned 50% by Cloyce A. Talbott and directly owned 50% by +A. Glenn Patterson. +(5) +IDC Enterprises, Ltd. is 50% owned by Cloyce A. +Talbott and 50% owned by A. Glenn Patterson. +(6) +SSSL, Ltd. is a limited partnership in which +children and grandchildren of Mr. Talbott are beneficiaries +and Mr. Talbott is the general partner. +(7) +Robert and Thomas M. Patterson are A. Glenn +Patterson’s adult children. The Glenn Patterson Family +Limited Partnership is a partnership in which each of +Mr. Patterson’s children shares equally and +Mr. Patterson is the manager. +(8) +Revenues included in IDC Enterprises, Ltd. +revenues. +In 2003, 2002 and 2001, we paid approximately +$740,000, $279,000 and $387,000, respectively, to TMP Truck and +Trailer LP (“TMP”), an entity owned by Thomas M. +Patterson (son of A. Glenn Patterson), for certain +equipment and metal fabrication services. Purchases from TMP +were at current market prices. +In 2003, we paid approximately $209,000 to Melco +Services (“Melco”) for dirt contracting services and +$59,000 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. +26 +Table of Contents +Liquidity and Capital Resources +As of December 31, 2003, we had working +capital of $199.6 million including cash and cash +equivalents of $100.5 million. For 2003, our significant +sources of cash flow were: +• +$161.5 million derived from operations, +• +$10.3 million from the exercise of stock +options and warrants, and +• +$4.5 million from the sale of certain +property and equipment. +We used approximately $157.9 million: +• +to make capital expenditures for the betterment +and refurbishment of our drilling rigs, +• +for the acquisition and procurement of drilling +equipment, +• +to fund capital expenditures for our pressure +pumping and drilling and completion fluids divisions, and +• +to fund leasehold acquisition and development and +exploration of oil and natural gas properties. +In January 2003, we 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. +In February 2003, we 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. +In April 2003, we 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. +In May 2003, we acquired seven land-based +drilling rigs and related equipment from Hexadyne Drilling +Corporation for $10.1 million in cash. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +In May 2003, the Company, Patterson-UTI +Acquisition, LLC, a wholly-owned subsidiary of the Company +(“Sub”), and TMBR/Sharp Drilling, Inc., a Texas +corporation (“TMBR”), entered into an Agreement and +Plan of Merger, as amended by Amendment No. 1 to Agreement +and Plan of Merger, dated as of December 30, 2003, by and +among the same parties (the “Merger Agreement”), +pursuant to which, upon the satisfaction and completion of the +conditions to the merger contained in the Merger Agreement, +including approval of the Merger Agreement by at least +two-thirds of the shareholders of TMBR, TMBR will merge with and +into Sub with Sub being the surviving company. If the merger is +completed, each issued and outstanding share of common stock, +$.10 par value per share, of TMBR not owned directly or +indirectly by the Company or TMBR or held by TMBR shareholders +who validly exercise their dissenters’ rights under Texas +law, will be converted into the right to receive $9.09 in cash +from the Company and 0.312166 of a share of common stock, $0.01 +par value per share, of the Company (the “Company Common +Stock”), for a total of approximately $40.4 million in +cash and approximately 1.39 million shares of Company +Common Stock based on the outstanding shares of TMBR common +stock as of January 5, 2004. The Company currently intends +to pay the cash portion of the merger consideration to TMBR +shareholders out of funds available on hand and existing +financing facilities. The TMBR shareholders’ meeting is +currently scheduled for February 11, 2004. +In November 2003, we 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. +In addition to the above mentioned acquisitions, +we spent approximately $3.1 million on other acquisitions +of assets and costs associated with the acquisitions completed +during 2003. +27 +Table of Contents +We believe that the current level of cash and +short-term investments, together with cash generated from +operations, should be sufficient to meet our capital needs. From +time to time, acquisition opportunities are reviewed relating to +our business. The timing, size or success of any acquisition and +the associated capital commitments are unpredictable. Over the +longer term, should further opportunities for growth requiring +capital arise, we believe we would be able to satisfy these +needs through a combination of working capital, cash generated +from operations, and either debt or equity financing. However, +there can be no assurance that such capital would be available. +Results of Operations +Comparison of the years ended +December 31, 2003 and 2002 +The following tables summarize operations by +business segment for the twelve months ended December 31, +2003 and 2002: +Years Ended December 31, +Contract Drilling +2003 +2002 +% Change +(Dollars in thousands) +Revenues +$ +639,694 +$ +410,295 +55.9 +% +Direct operating costs +$ +475,224 +$ +318,201 +49.3 +% +Selling, general, and administrative +$ +4,425 +$ +3,987 +11.0 +% +Depreciation and amortization +$ +84,379 +$ +80,500 +4.8 +% +Operating income +$ +75,666 +$ +7,607 +894.7 +% +Operating days +68,798 +45,919 +49.8 +% +Average revenue per operating day +$ +9.30 +$ +8.94 +4.0 +% +Average direct operating costs per operating day +$ +6.91 +$ +6.93 +(0.3 +)% +Number of owned rigs at end of period +343 +324 +5.9 +% +Average number of rigs owned during period +336 +323 +4.0 +% +Average rigs operating +188 +126 +49.2 +% +Rig utilization percentage +56 +% +39 +% +43.6 +% +Capital expenditures +$ +95,175 +$ +68,516 +38.9 +% +The following table illustrates the average +market price of natural gas and our average rigs operating for +each of the fiscal quarters in 2003 and 2002: +1st +2nd +3rd +4th +Quarter +Quarter +Quarter +Quarter +2003: +Average natural gas price +$ +5.91 +$ +5.70 +$ +4.88 +$ +5.29 +Average rigs operating +176 +195 +192 +191 +2002: +Average natural gas price +$ +2.51 +$ +3.41 +$ +3.20 +$ +4.31 +Average rigs operating +117 +119 +127 +140 +The average market price of natural gas improved +to $5.45 per Mcf in 2003 compared to $3.36 per Mcf in 2002, +resulting in an increase in demand for our contract drilling +services. Our average number of rigs operating increased to 188 +in 2003 from 126 in 2002. +Revenues and direct operating costs increased as +a result of the increased number of operating days in 2003. +Revenue per operating day increased as a result of increased +demand for our services which resulted in additional increases +in revenues and operating income. As a result of the increased +utilization of our drilling rigs in 2003, significant capital +expenditures were incurred to modify and upgrade our existing +drilling rigs and +28 +Table of Contents +to acquire additional related equipment to meet +the increased demand. Increased depreciation expense in 2003 +resulted from this increased level of capital spending, as well +as acquisitions. +Years Ended December 31, +Pressure Pumping +2003 +2002 +% Change +(Dollars in thousands) +Revenues +$ +46,083 +$ +32,996 +39.7 +% +Direct operating costs +$ +26,184 +$ +19,802 +32.2 +% +Selling, general, and administrative +$ +5,683 +$ +4,301 +32.1 +% +Depreciation +$ +3,774 +$ +2,803 +34.6 +% +Operating income +$ +10,442 +$ +6,090 +71.5 +% +Total jobs +5,667 +3,796 +49.3 +% +Average revenue per job +$ +8.13 +$ +8.69 +(6.4 +)% +Average direct operating costs per job +$ +4.62 +$ +5.22 +(11.5 +)% +Capital expenditures +$ +10,524 +$ +7,399 +42.2 +% +The increases in revenues and expenses for our +pressure pumping operations were attributable to improved +industry conditions, as discussed in “Contract +Drilling” above, and continued expansion of our pressure +pumping services into the Appalachian regions of Kentucky and +West Virginia. This expansion also resulted in increases in +selling, general and administrative expenses and depreciation in +2003 compared to 2002. +Years Ended December 31, +Drilling and Completion Fluids +2003 +2002 +% Change +(Dollars in thousands) +Revenues +$ +69,230 +$ +69,943 +(1.0 +)% +Direct operating costs +$ +61,424 +$ +60,762 +1.1 +% +Selling, general, and administrative +$ +7,447 +$ +7,243 +2.8 +% +Depreciation and amortization +$ +2,319 +$ +2,216 +4.6 +% +Operating loss +$ +(1,960 +) +$ +(278 +) +605.0 +% +Total jobs +1,931 +1,457 +32.5 +% +Average revenue per job +$ +35.85 +$ +48.00 +(25.3 +)% +Average direct operating costs per job +$ +31.81 +$ +41.70 +(23.7 +)% +Capital expenditures +$ +912 +$ +1,571 +(41.9 +)% +The decrease in revenues was primarily due to the +decrease in larger jobs completed in the Gulf of Mexico as +activity in the Gulf of Mexico continued to be slow despite +improved natural gas prices in 2003. The decrease in revenues +from the Gulf of Mexico was largely offset by increased demand +for our land-based drilling and completion fluids services. +Land-based drilling and completion fluids jobs typically +generate less +29 +Table of Contents +revenue per job than offshore jobs. As a result, +our average revenue per job decreased in 2003 compared to 2002. +Years Ended December 31, +Oil and Natural Gas Production and Exploration +2003 +2002 +% Change +(Dollars in thousands) +Revenues +$ +21,163 +$ +14,723 +43.7 +% +Direct operating costs +$ +4,808 +$ +3,956 +21.5 +% +Selling, general, and administrative +$ +1,489 +$ +1,571 +(5.2 +)% +Depreciation and depletion +$ +7,082 +$ +5,251 +34.9 +% +Operating income +$ +7,784 +$ +3,945 +97.3 +% +Capital expenditures +$ +10,484 +$ +6,357 +64.9 +% +Average net daily oil production (Bbls) +788 +794 +(0.8 +)% +Average net daily gas production (Mcf) +5,656 +5,109 +10.7 +% +Average oil sales price (per Bbl) +$ +30.54 +$ +25.02 +22.1 +% +Average gas sales price (per Mcf) +$ +4.97 +$ +2.91 +70.8 +% +Increased revenues and operating income are +primarily attributable to increased prices received from sales +of oil and natural gas and increased production of natural gas +in 2003. Depreciation and depletion expense primarily increased +as a result of increased production of natural gas in 2003 as +compared to 2002, as well as an increase of approximately +$700,000 associated with expenses incurred to partially impair +certain oil and natural gas properties. +Years Ended December 31, +Corporate and Other +2003 +2002 +% Change +(Dollars in thousands) +Selling, general, and administrative +$ +8,665 +$ +9,038 +(4.1 +)% +Bad debt expense +$ +259 +$ +320 +(19.1 +)% +Depreciation and amortization +$ +444 +$ +446 +(0.4 +)% +Other income +$ +2,174 +$ +538 +304.1 +% +Restructuring and other charges +$ +(2,452 +) +$ +4,700 +N/A +In 2003, Restructuring and other charges reflects +a payment received in the first quarter of 2003 of approximately +$2.5 million as settlement for contract drilling services +previously provided in Mexico by Norton Drilling Company Mexico, +Inc., a wholly-owned subsidiary of Patterson-UTI. The underlying +accounts receivable balance had been reserved as uncollectible +at the time of our acquisition of Norton Drilling Company +Mexico, Inc. in 1999. In 2002, Restructuring and other charges +reflects a $4.7 million charge due to the financial failure +of a workers’ compensation insurance carrier we used from +1992 until March 2001. +30 +Table of Contents +Comparison of the years ended +December 31, 2002 and 2001 +The following tables summarize operations by +business segment for the twelve months ended December 31, +2002 and 2001: +Years Ended December 31, +Contract Drilling +2002 +2001 +% Change +(Dollars in thousands) +Revenues +$ +410,295 +$ +839,931 +(51.2 +)% +Direct operating costs +$ +318,201 +$ +487,343 +(34.7 +)% +Selling, general, and administrative +$ +3,987 +$ +5,277 +(24.4 +)% +Depreciation and amortization +$ +80,500 +$ +72,797 +10.6 +% +Operating income +$ +7,607 +$ +274,514 +(97.2 +)% +Operating days +45,919 +76,871 +(40.3 +)% +Average revenue per operating day +$ +8.94 +$ +10.93 +(18.2 +)% +Average direct operating costs per operating day +$ +6.93 +$ +6.34 +9.3 +% +Number of owned rigs at end of period +324 +319 +1.6 +% +Average number of rigs owned during period +323 +302 +7.0 +% +Average rigs operating +126 +211 +(40.3 +)% +Rig utilization percentage +39 +% +70 +% +(44.3 +)% +Capital expenditures +$ +68,516 +$ +150,788 +(54.6 +)% +The following table illustrates the average +market price of natural gas and our average rigs operating for +each of the fiscal quarters in 2002 and 2001: +1st +2nd +3rd +4th +Quarter +Quarter +Quarter +Quarter +2002: +Average natural gas price +$ +2.51 +$ +3.41 +$ +3.20 +$ +4.31 +Average rigs operating +117 +119 +127 +140 +2001: +Average natural gas price +$ +6.23 +$ +4.41 +$ +2.78 +$ +2.70 +Average rigs operating +231 +248 +225 +140 +Our rig count began to decline in the third +quarter of 2001 and continued until March 2002 when our rig +count bottomed at 103 rigs (90 rigs in the U.S. and 13 rigs in +Canada). The deterioration in our rig count was primarily the +result of weakening natural gas prices through mid-February +2002. Natural gas prices then rebounded somewhat and our rig +count improved marginally during the period from March through +September 2002. In the fourth quarter of 2002, consistent with +improved natural gas prices, our rig count continued to improve +and averaged 140 rigs (132 rigs in the U.S. and 8 rigs in +Canada). +The decreased operating results in 2002 were +reflective of a significant decline in demand for our contract +drilling services as evidenced by decreases in the number of +operating days and average rig utilization. Increased +competition during 2002 for available jobs resulted in downward +pricing pressure and decreased operating revenues. Increased +operating costs per operating day were primarily attributable to +increased labor costs, including payroll expenses and +workers’ compensation insurance costs. Payroll expenses +increased as experienced field personnel were retained despite +the significant decline in our average rig utilization. +Management believes this strategy is beneficial as it +(1) retains experienced personnel and (2) facilitates +our response to increased demand levels as industry conditions +improve. General and administrative expenses decreased primarily +as a result of reduced incentive compensation in 2002. +Depreciation and amortization increased in 2002 primarily as a +result of (1) significant capital expenditures in 2001 and +2002 to modify and +31 +Table of Contents +upgrade our drilling fleet and (2) our +acquisition of drilling rigs and related equipment from Cleere +Drilling Company in December 2001. +Years Ended December 31, +Pressure Pumping +2002 +2001 +% Change +(Dollars in thousands) +Revenues +$ +32,996 +$ +39,600 +(16.7 +)% +Direct operating costs +$ +19,802 +$ +21,146 +(6.4 +)% +Selling, general, and administrative +$ +4,301 +$ +3,910 +10.0 +% +Depreciation +$ +2,803 +$ +1,895 +47.9 +% +Operating income +$ +6,090 +$ +12,649 +(51.9 +)% +Total jobs +3,796 +4,609 +(17.6 +)% +Average revenue per job +$ +8.69 +$ +8.59 +1.2 +% +Average direct operating costs per job +$ +5.22 +$ +4.59 +13.7 +% +Capital expenditures +$ +7,399 +$ +7,756 +(4.6 +)% +The decreases in revenues and expenses for our +pressure pumping operations were primarily attributable to +industry conditions, as discussed in “Contract +Drilling” above. Expansion of our pressure pumping services +in 2001 and 2002 into the Appalachian regions of Kentucky and +West Virginia resulted in increased depreciation and selling, +general, and administrative expenses in 2002. Additionally, +direct operating costs per job increased in 2002 since a portion +of direct operating costs remain constant despite fluctuating +activity levels. +Years Ended December 31, +Drilling and Completion Fluids +2002 +2001 +% Change +(Dollars in thousands) +Revenues +$ +69,943 +$ +94,456 +(26.0 +)% +Direct operating costs +$ +60,762 +$ +80,034 +(24.1 +)% +Selling, general, and administrative +$ +7,243 +$ +7,936 +(8.7 +)% +Depreciation and amortization +$ +2,216 +$ +2,644 +(16.2 +)% +Operating income (loss) +$ +(278 +) +$ +3,842 +N/A +Total jobs +1,457 +1,920 +(24.1 +)% +Average revenue per job +$ +48.00 +$ +49.20 +(2.4 +)% +Average direct operating costs per job +$ +41.70 +$ +41.68 +0.0 +% +Capital expenditures +$ +1,571 +$ +4,937 +(68.2 +)% +The decrease in revenues for our drilling and +completion fluids operations were primarily attributable to +industry conditions, as discussed in “Contract +Drilling” above, and the resulting 24.1% decline in the +number of jobs completed. Direct operating costs per job +increased despite reduced activity levels due to a portion of +32 +Table of Contents +the segment’s operating expenses being fixed +in nature. The 8.7% decrease in selling, general, and +administrative expense is primarily the result of reduced +employee incentive compensation in 2002. +Years Ended December 31, +Oil and Natural Gas Production and Exploration +2002 +2001 +% Change +(Dollars in thousands) +Revenues +$ +14,723 +$ +15,988 +(7.9 +)% +Direct operating costs +$ +3,956 +$ +5,190 +(23.8 +)% +Selling, general, and administrative +$ +1,571 +$ +1,537 +2.2 +% +Depreciation and depletion +$ +5,251 +$ +8,505 +(38.3 +)% +Operating income +$ +3,945 +$ +756 +421.8 +% +Capital expenditures +$ +6,357 +$ +7,956 +(20.1 +)% +Average net daily oil production (Bbls) +794 +739 +7.4 +% +Average net daily gas production (Mcf) +5,109 +4,654 +9.8 +% +Average oil sales price (per Bbl) +$ +25.02 +$ +24.88 +0.6 +% +Average gas sales price (per Mcf) +$ +2.91 +$ +4.12 +(29.4 +)% +Decreased revenues are attributable to lower +average prices received from sales of natural gas. Direct +operating costs declined in 2002 primarily due to the +divestiture of marginally productive wells in 2002, thus +reducing lease operating costs. Depreciation and depletion +declined in 2002 primarily due to significant decreased +depletion expense in 2002 as a result of increased commodity +prices at December 31, 2002. +Years Ended December 31, +Corporate and Other +2002 +2001 +% Change +(Dollars in thousands) +Selling, general, and administrative +$ +9,038 +$ +9,901 +(8.7 +)% +Bad debt expense +$ +320 +$ +2,045 +(84.4 +)% +Depreciation and amortization +$ +446 +$ +318 +40.3 +% +Other income +$ +538 +$ +820 +(34.4 +)% +Merger costs +$ +— +$ +5,943 +N/A +Restructuring and other charges +$ +4,700 +$ +7,202 +(34.7 +)% +Capital expenditures +$ +— +$ +5,320 +N/A +The decrease in selling, general, and +administrative expense of 8.7% primarily relates to reduced +employee incentive compensation in 2002. Restructuring and other +charges reflect a $4.7 million charge taken in the second +quarter of 2002 due to the financial failure of a workers’ +compensation insurance carrier we used from 1992 until March +2001. Merger costs and restructuring and other charges in 2001 +include an aggregate of $13.1 million for professional +fees, severance and related expenses, closing of duplicate +operational facilities and costs to amend our credit facilities +associated with the merger with UTI. +Income Taxes +Years Ended December 31, +2003 +2002 +2001 +(Dollars in thousands) +Income before income tax +$ +88,157 +$ +3,839 +$ +266,495 +Income tax expense +32,362 +1,670 +102,333 +Effective tax rate +36.7 +% +43.5 +% +38.4 +% +Net operating losses were fully utilized in 2001 +and our remaining alternative minimum tax credit of $602,000 may +be carried forward indefinitely. Other deferred tax assets +consist primarily of various allowance accounts and tax deferred +expenses expected to generate a future tax benefit of +approximately $15.8 million. +33 +Table of Contents +Our effective income tax rate of 36.7% for 2003 +is primarily attributable to a federal rate of 35.0% and a state +income tax rate of 1.5%. The impact of permanent differences was +not significant in 2003. The significance of the impact of the +permanent differences of approximately 6.0% to our effective +income tax rate in 2002 was largely attributable to our reduced +2002 pretax earnings. +We record non-cash deferred federal income taxes +based primarily on the relationship between the amount of our +unused federal net operating loss carryforwards and the +temporary differences between the book basis and tax basis in +our assets. Deferred tax assets and liabilities are measured +using enacted tax rates expected to apply to taxable income in +the year in which those temporary differences are expected to be +settled. As a result of fully recognizing the benefit of our +deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We incurred deferred income tax +expense of approximately $17.3 million, $23.5 million, and +$14.6 million for 2003, 2002, and 2001, respectively. +Volatility of Oil and Natural Gas +Prices +Our revenue, profitability, and future rate of +growth are substantially dependent upon prevailing prices for +oil and natural gas, with respect to all of our operating +segments. Historically, oil and natural gas prices and markets +have been volatile. Prices are affected by market supply and +demand factors as well as actions of state and local agencies, +the United States and foreign governments, and international +cartels. All of these factors are beyond our control. Natural +gas prices fell from an average of $6.23 per Mcf in the first +quarter of 2001 to an average of $2.51 per Mcf for the same +period in 2002. During this same period, the average number of +our rigs operating dropped by approximately 50%. The average +market price of natural gas improved to $5.45 in 2003 compared +to $3.36 in 2002, resulting in an increase in demand for our +drilling services. Our average number of rigs operating +increased to 188 in 2003 from 126 in 2002. We expect oil and +natural gas prices to continue to be volatile and to affect our +financial condition and operations and ability to access sources +of capital. +The contract drilling business experienced +increased demand for drilling services in 1997, 2000 and 2001. +However, except for those periods and other occasional upturns, +generally, there have been substantially more drilling rigs +available than necessary to meet demand in most operational and +geographic segments of the North American land drilling +industry. As a result, drilling contractors have had difficulty +sustaining profit margins. +Impact of Inflation +We believe that inflation will not have a +significant near-term impact on our financial position. +Recently-Issued Accounting Standards +The Financial Accounting Standards Board +(“FASB”) issued Statement of Financial Accounting +Standards No. 142, “Goodwill and Other Intangible +Assets,” (“SFAS No. 142”) in June 2001. SFAS +No. 142 supersedes APB Opinion No. 17, +“Intangible Assets.” Under the provisions of SFAS +No. 142, which the Company adopted on January 1, 2002, +goodwill is no longer amortized but is subject to an annual +impairment test. During the year ended December 31, 2001, +goodwill amortization totaled approximately $4.7 million. +The FASB issued Statement of Financial Accounting +Standards No. 143, “Accounting for Asset Retirement +Obligations,” (“SFAS No. 143”) in June 2001. +SFAS No. 143 addresses financial accounting requirements +for retirement obligations associated with tangible long-lived +assets. The Company adopted SFAS No. 143 in January 2003. +As a result, a charge of $469,000 (net of tax) was recorded as a +cumulative effect of a change in accounting principle during +2003. The change relates to the cost associated with the future +abandonment of oil and natural gas properties. The related +effect to basic and diluted earnings per share as a result of +the change in accounting principle was a decrease of $0.01 per +share for the twelve months ended December 31, 2003. +34 +Table of Contents +The FASB issued Statement of Financial Accounting +Standards No. 145, “Rescission of FASB Statements +No. 4, 44, and 64, Amendment of FASB Statement No. 13, +and Technical Corrections,” (“SFAS No. 145”) +in April 2002. SFAS No. 145 amends existing +authoritative pronouncements to make various technical +corrections, clarify meanings, or describe their applicability +under changed conditions. The provisions of SFAS No. 145, +which the Company adopted January 1, 2003, did not have a +material impact on the Company’s consolidated financial +statements. +The FASB issued Statement of Financial Accounting +Standards No. 146, “Accounting for Costs Associated +with Exit or Disposal Activities,” (“SFAS +No. 146”) in June 2002. SFAS No. 146 is +effective for exit or disposal activities that are initiated +after December 31, 2002. The adoption of SFAS No. 146 +did not have a material impact on the Company’s +consolidated financial statements. +The FASB issued Statement of Financial Accounting +Standards No. 148, “Accounting for Stock-Based +Compensation,” (“SFAS No. 148”) in December +2002. SFAS No. 148 amends the disclosure requirements of +Statement of Financial Accounting Standards No. 123 to +require prominent disclosures in both annual and interim +financial statements about the method of accounting for +stock-based employee compensation and the effect of the method +used on reported results. The provisions of SFAS No. 148, +which the Company adopted on January 1, 2003, did not have +a material impact on the Company’s consolidated financial +statements (see Note 12 of Notes to Consolidated Financial +Statements). +The FASB issued Statement of Financial Accounting +Standards No. 149, “Amendment of Statement 133 on +Derivative Instruments and Hedging Activities,” (“SFAS +No. 149”) in April 2003. SFAS No. 149 amends and +clarifies financial accounting and reporting for derivative +instruments, including certain derivative instruments embedded +in other contracts and for hedging activities under Statement of +Financial Accounting Standards No. 133, “Accounting +for Derivative Instruments and Hedging Activities.” SFAS +No. 149 is effective for existing contracts and new +contracts entered into after June 30, 2003. The provisions +of SFAS No. 149, which the Company adopted on July 1, +2003, did not have a material impact on the Company’s +consolidated financial statements. +The FASB issued Statement of Financial Accounting +Standards No. 150, “Accounting for Certain Financial +Instruments with Characteristics of both Liabilities and +Equity,” (“SFAS No. 150”) in May 2003. SFAS +No. 150 establishes standards for how an issuer classifies +and measures certain financial instruments with characteristics +of both liabilities and equity. The Company has no financial +instruments which are subject to SFAS No. 150. +The FASB issued Interpretation No. 45, +“Guarantor’s Accounting and Disclosure Requirements, +Including Guarantees of Indebtedness of Others,” +(“FIN 45”) which the Company adopted effective +January 1, 2003. FIN 45 requires that upon issuance of +certain types of guarantees, a guarantor recognize and account +for the fair value of the guarantee as a liability. FIN 45 +contains exclusions to this requirement, including the exclusion +of a parent’s guarantee of its subsidiaries’ debt to a +third party. The adoption of FIN 45 did not have a material +impact on the Company’s consolidated financial statements. +The FASB issued Interpretation No. 46, +“Consolidation of Variable Interest Entities,” +(“FIN 46”) which addresses the consolidation of +variable interest entities (“VIEs”) by business +enterprises that are the primary beneficiaries. A VIE is an +entity that does not have sufficient equity investment at risk +to permit it to finance its activities without additional +subordinated financial support, or whose equity investors lack +the characteristics of a controlling financial interest. The +primary beneficiary of a VIE is the enterprise that has the +majority of the risks or rewards associated with the VIE. The +Company believes it has no interests in VIEs that will require +disclosure or consolidation under FIN 46. +Item 7A. +Quantitative and Qualitative Disclosures +About Market Risk +We currently have no exposure to interest rate +market risk as we have no outstanding balance under our credit +facility. Should we incur a balance in the future, we would have +exposure associated with the floating rate of the interest +charged on that balance. The revolving credit facility calls for +periodic interest payments at a floating rate ranging from LIBOR +plus 1.75% to 2.75%. The applicable rate above LIBOR (1.75% at +35 +Table of Contents +December 31, 2003) is based upon our +trailing twelve-month earnings before interest expense, income +taxes and depreciation, depletion and amortization expense. Our +exposure to interest rate risk due to changes in LIBOR is not +expected to be material. +We conduct some business in Canadian dollars +through our Canadian land-based drilling operations. The +exchange rate between Canadian dollars and U.S. dollars has +fluctuated over the last ten years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and earnings of +our Canadian operations will be reduced when they are translated +to U.S. dollars. Also, the value of our Canadian net assets in +U.S. dollars may decline. +Item 8. +Financial Statements and Supplementary +Data. +Financial Statements are filed as a part of this +Report at the end of Part IV hereof beginning at +page F-1, Index to Consolidated Financial Statements, and +are incorporated herein by this reference. +Item 9. +Changes in and Disagreements with +Accountants on Accounting and Financial +Disclosure. +None. +Item 9A. +Controls and Procedures. +As of the end of the period covered by this +Annual Report on Form 10-K, the effectiveness of our +disclosure controls and procedures (as defined in +Rules 13a-15(e) and 15d-15(e) promulgated under the +Securities Exchange Act of 1934) was evaluated by our +management, with the participation of our Chief Executive +Officer, Cloyce A. Talbott (principal executive officer), +and our Vice President, Chief Financial Officer, Secretary and +Treasurer, Jonathan D. Nelson (principal financial officer). +Messrs. Talbott and Nelson have concluded that our +disclosure controls and procedures are effective, as of the end +of the period covered by this Report, to help ensure that +information we are required to disclose in reports that we file +with the SEC is accumulated and communicated to management and +recorded, processed, summarized and reported within the time +periods prescribed by the SEC. +There were no changes in our internal control +over financial reporting that occurred during our last fiscal +quarter (the quarter ended December 31, 2003) that have +materially affected, or are reasonably likely to materially +affect, our internal control over financial reporting. +36 +Table of Contents +PART III +The information required by Part III is +omitted from this Report because Patterson-UTI will file a +definitive proxy statement pursuant to Regulation 14A of +the Securities Exchange Act of 1934 no later than 120 days +after the end of the fiscal year covered by this Report and +certain information included therein is incorporated herein by +reference. +Item 10. +Directors and Executive Officers of the +Registrant. +The information required by this Item is +incorporated herein by reference to the Proxy Statement. +Item 11. +Executive Compensation. +The information required by this Item is +incorporated herein by reference to the Proxy Statement. +Item 12. +Security Ownership of Certain Beneficial +Owners and Management. +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. +37 +Table of Contents +PART IV +Item 15. +Exhibits, Financial Statement Schedules and +Reports on Form 8-K. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and +qualifying accounts is filed herewith on page S-1. +All other financial statement schedules have been +omitted because they are not applicable or the information +required therein is included elsewhere in the financial +statements or notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or +incorporated by reference herein. +2.1 +Agreement and Plan of Merger, dated as of +May 26, 2003, by and among Patterson-UTI Energy, Inc., +Patterson-UTI Acquisition, LLC and TMBR/Sharp Drilling, Inc.(1) +2.2 +Amendment No. 1 to Agreement and Plan of +Merger, dated as of December 30, 2003, by and among +Patterson-UTI Energy, Inc., Patterson-UTI Acquisition, LLC and +TMBR/Sharp Drilling, Inc.(2) +3.1 +Restated Certificate of Incorporation, as +amended.(3) +3.2 +Amended and Restated Bylaws.(4) +4.1 +Rights Agreement dated January 2, 1997, +between Patterson Energy, Inc. and Continental Stock +Transfer & Trust Company.(5) +4.2 +Amendment to Rights Agreement dated as of +October 23, 2001.(6) +4.3 +Restated Certificate of Incorporation, as amended +(See Exhibit 3.1) +4.4 +Registration Rights Agreement with Bear, Stearns +and Co. Inc., dated March 25, 1994, as assigned by REMY +Capital Partners III, L.P.(4) +4.5 +Patterson-UTI Energy, Inc. 1993 Stock Incentive +Plan, as amended.(7)* +4.6 +Patterson-UTI Energy, Inc. Non-Employee +Directors’ Stock Option Plan, as amended.(8)* +4.7 +Amended and Restated Patterson-UTI Energy, Inc. +2001 Long-Term Incentive Plan.(9)* +4.8 +Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan.(3)* +4.9 +Amended and Restated Patterson-UTI Energy, Inc. +Non-Employee Director Stock Option Plan.(3)* +4.10 +Amended and Restated Patterson-UTI Energy, Inc. +1996 Employee Stock Option Plan.(10)* +4.11 +1997 Stock Option Plan of DSI Industries, +Inc.(11)* +4.12 +Stock Option Agreement dated July 20, 2001 +between Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.).(4)* +10.1 +For additional material contracts, see +Exhibits 4.1, 4.2 and 4.4 through 4.11. +10.2 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel.* +10.3 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and A. Glenn Patterson.* +10.4 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott.* +10.5 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns.* +10.6 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Jonathan D. Nelson.* +10.7 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III.* +10.8 +Model Form Operating Agreement.(12) +38 +Table of Contents +10.9 +Form of Drilling Bid Proposal and Footage +Drilling Contract.(12) +10.10 +Form of Turnkey Drilling Agreement.(12) +14.1 +Patterson-UTI Energy, Inc. Code of Business +Conduct and Ethics for Senior Financial Executives. +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Accountants — +PricewaterhouseCoopers LLP. +23.2 +Consent of Independent Petroleum +Engineer — M. Brian Wallace, P.E. +31.1 +Certification of Chief Executive Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +31.2 +Certification of Chief Financial Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +32.1 +Certification of Chief Executive Officer and +Chief Financial Officer pursuant to 18 USC +Section 1350, as adopted pursuant to Section 906 of +the Sarbanes-Oxley Act of 2002. +(1) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K of TMBR/Sharp Drilling, Inc. +filed on May 27, 2003. +(2) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K filed on December 31, +2003. +(3) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended June 30, +2003, filed on July 28, 2003. +(4) +Incorporated herein by reference to Item 14, +“Exhibits, Financial Statement Schedules and Reports on +Form 8-K” to Annual Report on Form 10-K for the +fiscal year ended December 31, 2001, filed on +March 19, 2002. +(5) +Incorporated herein by reference to Item 2, +“Exhibits” to Registration Statement on Form 8-A +filed on January 14, 1997. +(6) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended September 30, +2001, filed on October 31, 2001. +(7) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-47917) filed on March 13, 1998. +(8) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-39471) filed on November 4, 1997. +(9) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60470) filed on November 27, 2002. +(10) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60466) filed on July 25, 2001. +(11) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60470) filed on July 25, 2001. +(12) +Incorporated herein by reference to Item 27, +“Exhibits” to Registration Statement on Form SB-2 +(File No. 33-68058-FW) filed on August 30, 1993. +* +Management Contract or Compensatory Plan +identified as required by Item 15(a)(3) of Form 10-K. +(b) Reports on Form 8-K. +On December 31, 2003, the Company filed a +Current Report on Form 8-K, dated December 30, 2003, +reporting the amendment to its Agreement and Plan of Merger with +TMBR/Sharp Drilling, Inc. to extend the date under which the +parties have certain rights of termination to February 14, +2004 from December 31, 2003. +39 +Table of Contents +INDEX TO CONSOLIDATED FINANCIAL +STATEMENTS +Page +Report of Independent Auditors; +PricewaterhouseCoopers LLP +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of +December 31, 2003 and 2002 +F-3 +Consolidated Statements of Income for the years +ended December 31, 2003, 2002, and 2001 +F-4 +Consolidated Statements of Changes In +Stockholders’ Equity for the years ended December 31, +2003, 2002, and 2001 +F-5 +Consolidated Statements of Changes In Cash Flows +for the years ended December 31, 2003, 2002, and 2001 +F-6 +Notes to Consolidated Financial Statements +F-8 +F-1 +Table of Contents +REPORT OF INDEPENDENT AUDITORS +The Board of Directors and Stockholders of +Patterson-UTI Energy, Inc. +In our opinion, the consolidated financial +statements listed in the accompanying index present fairly, in +all material respects, the financial position of Patterson-UTI +Energy, Inc. and its subsidiaries at December 31, 2003 and +2002, and the results of their operations and their cash flows +for each of the three years in the period ended +December 31, 2003 in conformity with accounting principles +generally accepted in the United States of America. In addition, +in our opinion, the financial statement schedule on +page S-1 presents fairly, in all material respects, the +information set forth therein when read in conjunction with the +related consolidated financial statements. These financial +statements and financial statement schedule are the +responsibility of the Company’s management; our +responsibility is to express an opinion on these financial +statements and financial schedule based on our audits. We +conducted our audits of these statements in accordance with +auditing standards generally accepted in the United States of +America, which require that we plan and perform the audit to +obtain reasonable assurance about whether the financial +statements are free of material misstatement. An audit includes +examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by +management, and evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable +basis for our opinion. +As discussed in Notes 1 and 5 to the +consolidated financial statements, in accordance with Statement +of Financial Accounting Standards No. 142 “Goodwill +and Other Intangible Assets” beginning in 2002 the Company +no longer amortizes goodwill. +PricewaterhouseCoopers LLP +Houston, Texas +January 30, 2004 +F-2 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +December 31, +2003 +2002 +(In thousands, except share +data) +ASSETS +Current assets: +Cash and cash equivalents +$ +100,483 +$ +82,154 +Accounts receivable, net of allowance for +doubtful accounts of $2,133 and $3,144 at December 31, 2003 +and 2002, respectively +156,345 +99,014 +Federal and state income taxes receivable +12,667 +24,719 +Inventory +15,206 +15,323 +Deferred tax assets +16,449 +15,290 +Other +6,910 +6,515 +Total current assets +308,060 +243,015 +Property and equipment, at cost, net +693,631 +627,734 +Goodwill and other intangible assets, net +51,179 +51,313 +Investment in equity securities +20,274 +17,707 +Other +2,686 +2,740 +Total assets +$ +1,075,830 +$ +942,509 +LIABILITIES AND STOCKHOLDERS’ +EQUITY +Current liabilities: +Accounts payable: +Trade +$ +41,093 +$ +30,618 +Accrued revenue distributions +8,545 +6,266 +Other +6,743 +2,755 +Accrued expenses +52,066 +35,513 +Total current liabilities +108,447 +75,152 +Deferred tax liabilities +143,490 +127,006 +Other +3,822 +2,795 +Total liabilities +255,759 +204,953 +Commitments and contingencies +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized +200,000,000 shares with 82,483,148 and 81,576,674 issued +and 80,976,600 and 80,070,126 outstanding at December 31, +2003 and 2002, respectively +825 +816 +Additional paid-in capital +506,018 +489,201 +Retained earnings +316,329 +261,003 +Accumulated other comprehensive income (loss) +8,554 +(1,809 +) +Treasury stock, at cost, 1,506,548 shares +(11,655 +) +(11,655 +) +Total stockholders’ equity +820,071 +737,556 +Total liabilities and stockholders’ equity +$ +1,075,830 +$ +942,509 +The accompanying notes are an integral part of +these consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +Years Ended December 31, +2003 +2002 +2001 +(In thousands, except +per share data) +Operating revenues: +Drilling +$ +639,694 +$ +410,295 +$ +839,931 +Pressure pumping +46,083 +32,996 +39,600 +Drilling and completion fluids +69,230 +69,943 +94,456 +Oil and natural gas, sales +19,058 +12,738 +13,842 +Oil and natural gas, well operation fees +2,105 +1,985 +2,146 +776,170 +527,957 +989,975 +Operating costs and expenses: +Drilling +475,224 +318,201 +487,343 +Pressure pumping +26,184 +19,802 +21,146 +Drilling and completion fluids +61,424 +60,762 +80,034 +Oil and natural gas, operating and production +4,276 +3,672 +4,334 +Oil and natural gas, third party production +532 +284 +856 +Depreciation, depletion, and amortization +97,998 +91,216 +86,159 +General and administrative (includes $1,213, +$1,281 and $1,268 in 2003, 2002 and 2001, respectively, incurred +on behalf of third party working interest owners) +27,709 +26,140 +28,561 +Bad debt expense +259 +320 +2,045 +Merger costs +— +— +5,943 +Restructuring and other charges +(2,452 +) +4,700 +7,202 +Other +(2,174 +) +(538 +) +(820 +) +688,980 +524,559 +722,803 +Operating income +87,190 +3,398 +267,172 +Other income (expense): +Interest income +1,116 +1,110 +2,080 +Interest expense +(292 +) +(532 +) +(3,142 +) +Other +143 +(137 +) +385 +967 +441 +(677 +) +Income before income taxes and cumulative effect +of change in accounting principle +88,157 +3,839 +266,495 +Income tax expense (benefit): +Current +15,088 +(21,878 +) +87,773 +Deferred +17,274 +23,548 +14,560 +32,362 +1,670 +102,333 +Income before cumulative effect of change in +accounting principle +55,795 +2,169 +164,162 +Cumulative effect of change in accounting +principle, net of related income tax benefit of approximately +$287 +(469 +) +— +— +Net income +$ +55,326 +$ +2,169 +$ +164,162 +Net income per common share: +Basic: +Income before cumulative effect of change in +accounting principle +$ +0.69 +$ +0.03 +$ +2.15 +Cumulative effect of change in accounting +principle +(0.01 +) +— +— +Net income +$ +0.68 +$ +0.03 +$ +2.15 +Diluted: +Income before cumulative effect of change in +accounting principle +$ +0.68 +$ +0.03 +$ +2.07 +Cumulative effect of change in accounting +principle +(0.01 +) +— +— +Net income +$ +0.67 +$ +0.03 +$ +2.07 +Weighted average number of common shares +outstanding: +Basic +80,636 +78,705 +76,407 +Diluted +82,286 +81,252 +79,197 +The accompanying notes are an integral part of +these consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN +STOCKHOLDERS’ EQUITY +Common stock +Accumulated +Additional +other +Number +Paid-in +Retained +Comprehensive +Treasury +of Shares +Amount +Capital +Earnings +Income (loss) +Stock +Total +(In thousands) +December 31, 2000 +76,250 +$ +763 +$ +397,489 +$ +94,672 +$ +30 +$ +(11,655 +) +$ +481,299 +Issuance of common stock +1,260 +12 +31,405 +— +— +— +31,417 +Issuance of stock purchase warrant +— +— +2,600 +— +— +— +2,600 +Exercise of stock purchase warrants +121 +1 +1,819 +— +— +— +1,820 +Exercise of stock options +832 +8 +4,237 +— +— +— +4,245 +Tax benefit related to exercise of stock options +— +— +3,925 +— +— +— +3,925 +Foreign currency translation +— +— +— +— +(2,326 +) +— +(2,326 +) +Net income +— +— +— +164,162 +— +— +164,162 +December 31, 2001 +78,463 +784 +441,475 +258,834 +(2,296 +) +(11,655 +) +687,142 +Issuance of common stock +650 +7 +16,933 +— +— +— +16,940 +Exercise of stock options and warrants +2,464 +25 +15,714 +— +— +— +15,739 +Tax benefit related to exercise of stock options +— +— +15,079 +— +— +— +15,079 +Foreign currency translation +— +— +— +— +457 +— +457 +Change in unrealized gain on securities, net of +tax +— +— +— +— +30 +— +30 +Net income +— +— +— +2,169 +— +— +2,169 +December 31, 2002 +81,577 +816 +489,201 +261,003 +(1,809 +) +(11,655 +) +737,556 +Exercise of stock options and warrants +906 +9 +10,277 +— +— +— +10,286 +Tax benefit related to exercise of stock options +— +— +6,540 +— +— +— +6,540 +Foreign currency translation +— +— +— +— +8,773 +— +8,773 +Change in unrealized gain on securities, net of +tax +— +— +— +— +1,590 +— +1,590 +Net income +— +— +— +55,326 +— +— +55,326 +December 31, 2003 +82,483 +$ +825 +$ +506,018 +$ +316,329 +$ +8,554 +$ +(11,655 +) +$ +820,071 +The accompanying notes are an integral part of +these consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN CASH +FLOWS +Years ended December 31, +2003 +2002 +2001 +(In thousands) +Cash flows from operating activities: +Net income +$ +55,326 +$ +2,169 +$ +164,162 +Adjustments to reconcile net income to net cash +provided by operating activities: +Depreciation, depletion, and amortization +97,998 +91,216 +86,159 +Provision for bad debts +259 +320 +2,045 +Deferred income tax expense +17,274 +23,548 +14,560 +Tax benefit related to exercise of stock options +6,540 +15,079 +3,925 +Gain on sale of assets +(2,174 +) +(538 +) +(648 +) +Changes in operating assets and liabilities: +Accounts receivable +(55,791 +) +34,565 +6,648 +Federal income taxes receivable +10,919 +(23,216 +) +796 +Inventory and other current assets +(196 +) +(222 +) +(355 +) +Accounts payable +12,322 +(11,079 +) +(33,174 +) +Accrued expenses +14,026 +(771 +) +12,430 +Other liabilities +5,015 +362 +(2,542 +) +Net cash provided by operating activities +161,518 +131,433 +254,006 +Cash flows from investing activities: +Acquisitions, net of cash acquired +(40,832 +) +— +(40,546 +) +Purchases of property and equipment +(117,095 +) +(83,843 +) +(172,850 +) +Proceeds from sales of property and equipment +4,548 +1,813 +742 +Purchase of investment equity securities +— +(17,659 +) +— +Change in other assets +34 +1,097 +(1,101 +) +Net cash used in investing activities +(153,345 +) +(98,592 +) +(213,755 +) +Cash flows from financing activities: +Proceeds from issuance of notes payable +— +— +9,760 +Payments of notes payable +— +— +(89,176 +) +Proceeds from exercise of stock options and +warrants +10,286 +15,739 +6,065 +Net cash provided by (used in) financing +activities +10,286 +15,739 +(73,351 +) +Net increase (decrease) in cash and cash +equivalents +18,459 +48,580 +(33,100 +) +Effect of exchange rate changes on cash +(130 +) +(10 +) +(232 +) +Cash and cash equivalents at beginning of year +82,154 +33,584 +66,916 +Cash and cash equivalents at end of year +$ +100,483 +$ +82,154 +$ +33,584 +Supplemental disclosure of cash flow information: +Net cash received (paid) during the year for: +Interest +$ +(292 +) +$ +(532 +) +$ +(3,142 +) +Income taxes +2,730 +13,492 +(81,802 +) +The accompanying notes are an integral part of +these consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN CASH +FLOWS — (Continued) +Non-cash investing and financing activities: +During March 2002, the Company acquired five SCR +electric land-based drilling rigs through the acquisition of +Odin Drilling, Inc., for a purchase price of $16.9 million. +The purchase price consisted of 650,000 shares of common +stock valued at $26.06 per share. A deferred tax liability of +$4.1 million was recorded as a result of the transaction. +The transaction was accounted for as an acquisition of assets +and the purchase price was allocated among the assets acquired +based on their estimated fair market values. +During 2001 the Company acquired Jones Drilling +Corporation and certain assets of three other entities +affiliated with Jones Drilling Corporation for +$33.0 million, drilling rigs and related equipment from +Cleere Drilling Company for an aggregate purchase price of +$25.8 million and six drilling rigs through three separate +transactions for $15.7 million. Of the $74.6 million, +approximately $40.5 million was paid in cash as follows: +(in thousands) +Purchase price +$ +74,563 +Less non-cash items: +Common stock issued +(31,417 +) +Warrants issued +(2,600 +) +Total cash paid +$ +40,546 +The accompanying notes are an integral part of +these consolidated financial statements. +F-7 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS +1. +Description of Business and Summary of +Significant Accounting Policies +A description and basis of presentation +follows: +Description of +business — Patterson-UTI +Energy, Inc. and its wholly-owned subsidiaries, (collectively +referred to herein as “Patterson-UTI” or the +“Company”) is a leading provider of onshore contract +drilling services to major and independent oil and natural gas +operators in Texas, New Mexico, Oklahoma, Louisiana, +Mississippi, Colorado, Utah, Wyoming, and Western Canada. The +Company owns 343 drilling rigs. The Company provides pressure +pumping services to oil and natural gas operators primarily in +the Appalachian Basin. The Company provides drilling fluids, +completion fluids, and related services to oil and natural gas +operators in West Texas, Southeast New Mexico, South Texas, East +Texas, Oklahoma, the Gulf Coast regions of Texas and Louisiana, +and the Gulf of Mexico. The Company is also engaged in the +development, exploration, acquisition, and production of oil and +natural gas. The Company’s oil and natural gas business +operates primarily in producing regions of West Texas, Southeast +New Mexico, South Texas and Mississippi. +Basis of +presentation — The +consolidated financial statements of Patterson-UTI Energy, Inc. +and its wholly-owned subsidiaries have been prepared to give +retroactive effect to the merger between Patterson Energy, Inc. +(“Patterson”) and UTI Energy Corp. (“UTI”) +on May 8, 2001. The transaction was treated as a +reorganization within the meaning of Section 368(a) of the +Internal Revenue Code of 1986, as amended, and accounted for as +a pooling of interests for financial accounting purposes. +A summary of the significant accounting +policies follows: +Principles of +consolidation — The +consolidated financial statements include the accounts of +Patterson-UTI and its wholly-owned subsidiaries. All significant +intercompany accounts and transactions have been eliminated. +Management +estimates — The preparation +of financial statements in conformity with generally accepted +accounting principles requires management to make estimates and +assumptions that affect the reported amounts of assets and +liabilities and disclosure of contingent assets and liabilities +at the date of the financial statements and the reported amounts +of revenues and expenses during the reporting period. Actual +results could differ from those estimates. +Revenue +recognition — Revenues are +recognized when services are performed, except for revenues +earned under turnkey contract drilling arrangements which are +recognized using the completed contract method of accounting, as +described below. The Company follows the +percentage-of-completion method of accounting for footage +contract drilling arrangements. Under this method, drilling +revenues and costs related to a well in progress are recognized +proportionately over the time it takes to drill the well. +Percentage-of-completion is determined based upon the amount of +expenses incurred through the measurement date as compared to +total estimated expenses to be incurred drilling the well. Under +the percentage-of-completion method, management estimates are +relied upon in the determination of the total estimated expenses +to be incurred drilling the well. Due to the nature of turnkey +contract drilling arrangements and risks therein, the Company +follows the completed contract method of accounting for such +arrangements. Under this method, all drilling advances and costs +related to a well in progress are deferred and recognized as +revenues and expenses in the period the well is completed. +Provisions for losses on incomplete or in-process wells are made +when estimated total costs are expected to exceed estimated +total revenues. +Inventories — +Inventories consist primarily of chemical products to be used in +conjunction with the Company’s drilling and completion +fluids activities. The inventories are stated at the lower of +cost or market, determined by the first-in, first-out method. +F-8 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Property and +equipment — Property and +equipment is carried at cost less accumulated depreciation. +Depreciation is provided on the straight-line method over the +estimated useful lives. The method of depreciation does not +change when equipment becomes idle. The estimated useful lives +are defined below. +Useful Lives +(years) +Drilling rigs and related equipment +2-15 +Office furniture +3-10 +Buildings +5-20 +Automotive equipment +2-7 +Other +3-7 +Oil and natural gas +properties — Oil and natural +gas properties are accounted for using the successful efforts +method of accounting. Under the successful efforts method of +accounting, exploration costs which result directly 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 directly in discovering oil and natural gas +reserves are charged to expense when such determinations are +made. In accordance with Statement of Financial Accounting +Standards No. 19, “Financial Accounting and Reporting +by Oil and Gas Producing Companies,” (SFAS +“No. 19”) costs of exploratory wells are +initially capitalized to wells in progress until the outcome of +the drilling is known. We review wells in progress quarterly to +determine the related reserve classification. If the reserve +classification is uncertain after one year following the +completion of drilling, we consider the costs of the well to be +impaired and recognize the costs as expense. Geological and +geophysical costs, including seismic costs, and costs to carry +and retain undeveloped properties are charged to expense when +incurred. The capitalized costs of both developmental and +successful exploratory type wells, consisting of lease and well +equipment, lease acquisition costs, and intangible development +costs, are depreciated, depleted, and amortized on the +units-of-production method, based on petroleum engineer +estimates of proved oil and natural gas reserves of each +respective field. The Company reviews its proved oil and natural +gas properties for impairment when an event occurs such as +downward revisions in reserve estimates or decreases in oil and +natural gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are provided by our reserve +engineer. If the net book value of a field exceeds its +undiscounted cash flow estimate, impairment expense is measured +and recognized as the difference between its net book value and +discounted cash flow. Unproved oil and natural gas properties +are reviewed quarterly to determine impairment. The +Company’s intent to drill, lease expiration, and +abandonment of area are considered. Assessment of impairment is +made on a lease-by-lease basis. If an unproved property is +determined to be impaired, then costs related to that property +are expensed. Impairment expense is included in depreciation, +depletion, and amortization in the accompanying financial +statements. +Intangible +assets — Intangible assets +consist primarily of goodwill arising from business combinations +(see Note 5). Intangible assets other than goodwill are +amortized on a straight line basis over their estimated useful +lives. Covenants not to compete are amortized over their +underlying contractual lives of five years. Prior to 2002, +goodwill, representing the excess of the purchase price over the +estimated fair value of the net assets of the acquired business, +was amortized over the period of expected benefit of +15 years. However, effective January 1, 2002, the +Company adopted Statement of Financial Accounting Standards +No. 142, “Goodwill and Other Intangible Assets,” +(“SFAS No. 142”) which requires that the Company +cease amortization of all intangible assets having indefinite +useful economic lives. Such assets, including goodwill, are not +to be amortized until their lives are determined to be finite, +however, a recognized intangible asset with an indefinite useful +life should be tested for impairment annually or on an interim +basis if events or circumstances indicate that the fair value of +the asset has decreased below its carrying value. At +December 31, 2003, the Company evaluated its goodwill and +other intangible assets and determined that fair value had not +decreased below carrying value and no adjustment to impair +goodwill and other intangible assets was necessary in accordance +with SFAS No. 142. With respect to the Company’s +drilling and completion fluids business, the determination +F-9 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +that no impairment existed was based on the +Company’s expectations of improvement in the results of +operations for that business segment. If the expected +improvement in results does not occur, all or part of the +goodwill and other intangible assets of approximately +$10 million associated with that business segment may be +determined to be impaired. +The following table summarizes depreciation, +depletion, amortization, and impairment expense for 2003, 2002 +and 2001 (in millions): +2003 +2002 +2001 +Depreciation expense +$ +90.9 +$ +85.8 +$ +72.6 +Depletion expense +5.6 +4.4 +7.3 +Amortization expense +0.1 +0.3 +5.2 +Impairment of oil and natural gas properties +1.4 +0.7 +1.1 +Total +$ +98.0 +$ +91.2 +$ +86.2 +Maintenance and +repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing properties +are capitalized. +Retirements — +Upon disposition or retirement of property and equipment, the +cost and related accumulated depreciation are removed and any +resulting gain or loss is credited or charged to operations. +Investments in equity +securities — In accordance +with Statement of Financial Accounting Standards No. 115, +“Accounting for Certain Investments in Debt and Equity +Securities,” (“SFAS No. 115”) investments in +Available-for-Sale equity securities are recorded at fair value. +Unrealized gains and losses on such investments, net of tax, are +included in accumulated other comprehensive income (loss) in our +consolidated balance sheets as of December 31, 2003 and +2002, and are shown as a separate component of +stockholders’ equity (see Notes 3 and 6). +Earnings per +share — The Company provides +a dual presentation of its earnings per share; Basic Earnings +per Share (“Basic EPS”) and Diluted Earnings per Share +(“Diluted EPS”) in its Consolidated Statements of +Income. 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, 2003, 2002, and +2001, dilutive securities, consisting of certain stock options +and warrants (See Note 12) included in the calculation of +Diluted EPS were 1.7 million shares, 2.5 million +shares, and 2.8 million shares, respectively. At +December 31, 2003, 2002, and 2001, there were potentially +dilutive securities of 930,000, 328,500, and 490,000, +respectively, excluded from the calculation of Diluted EPS as +their exercise prices were greater than the average market price +for the respective year. +Income +taxes — The asset and +liability method is used in accounting for income taxes. Under +this method, deferred tax assets and liabilities are recognized +for operating loss and tax credit carryforwards and for the +future tax consequences attributable to differences between the +financial statement carrying amounts of existing assets and +liabilities and their respective tax bases. Deferred tax assets +and liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. 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. +F-10 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Stock based +compensation — The Company +grants stock options to employees and non-employee directors +under stock-based incentive compensation plans, (the +“Plans”). The Company accounts for all stock-based +employee compensation plans under the recognition and +measurement provisions of APB Opinion No. 25, +“Accounting for Stock Issued to Employees,” (“APB +No. 25”) and related interpretations. Under APB +No. 25, no stock-based employee compensation cost is +reflected in net income, as all options granted under those +plans had an exercise price equal to or in excess of the market +value of the underlying common stock on the date of grant. The +following table illustrates the effect on net income and +earnings per share as if the company had applied the fair value +recognition provisions of FASB Statement No. 123, +“Accounting for Stock-Based Compensation,” (“SFAS +No. 123”) to stock-based employee compensation: +Years Ended December 31, +2003 +2002 +2001 +(In thousands, except +per share amounts) +Net income, as reported +$ +55,326 +$ +2,169 +$ +164,162 +Deduct: Total stock-based employee compensation +expense determined under fair value based method for all awards, +net of related tax effects(1) +(10,506 +) +(5,296 +) +(7,053 +) +Pro forma net income (loss) +$ +44,820 +$ +(3,127 +) +$ +157,109 +Earnings (loss) per share: +Basic, as reported +$ +0.68 +$ +0.03 +$ +2.15 +Basic, pro forma +$ +0.56 +$ +(0.04 +) +$ +2.06 +Diluted, as reported +$ +0.67 +$ +0.03 +$ +2.07 +Diluted, pro forma +$ +0.54 +$ +(0.04 +) +$ +1.98 +Weighted-average fair value per share of options +granted(1) +$ +15.33 +$ +15.19 +$ +9.97 +(1) +See Note 12 for additional information regarding +the computations presented here. +The FASB issued Statement of Financial Accounting +Standards No. 148, “Accounting for Stock-Based +Compensation,” (“SFAS No. 148”) in December +2002. SFAS No. 148 amends the disclosure requirements of +SFAS No. 123 to require prominent disclosures in both +annual and interim financial statements about the method of +accounting for stock-based employee compensation and the effect +of the method used on reported results. The provisions of SFAS +No. 148, which the Company adopted on January 1, 2003, +did not have a material impact on the Company’s +consolidated financial statements (see Note 12). +Statement of cash +flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and unrestricted certificates of deposit with original +maturities of 90 days or less. +Recently Issued Accounting +Standards — The Financial +Accounting Standards Board (“FASB”) issued Statement +of Financial Accounting Standards No. 142, “Goodwill +and Other Intangible Assets,” (“SFAS +No. 142”) in June 2001. SFAS No. 142 supersedes +APB Opinion No. 17, “Intangible Assets.” Under +the provisions of SFAS No. 142, which the Company adopted +on January 1, 2002, goodwill is no longer amortized but is +subject to an annual impairment test. During the year ended +December 31, 2001, goodwill amortization totaled +approximately $4.7 million. +The FASB issued Statement of Financial Accounting +Standards No. 143, “Accounting for Asset Retirement +Obligations,” (“SFAS No. 143”) in June 2001. +SFAS No. 143 addresses financial accounting requirements +for retirement obligations associated with tangible long-lived +assets. The Company adopted SFAS No. 143 in January 2003. +As a result, a charge of $469,000 (net of tax) was recorded as a +cumulative effect of a change in accounting principle during +2003. The change relates to the cost associated with the +F-11 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +future abandonment of oil and natural gas +properties. The related effect to basic and diluted earnings per +share as a result of the change in accounting principle was a +decrease of $0.01 per share for the twelve months ended +December 31, 2003. +The FASB issued Statement of Financial Accounting +Standards No. 145, “Rescission of FASB Statements +No. 4, 44, and 64, Amendment of FASB Statement No. 13, +and Technical Corrections,” (“SFAS No. 145”) +in April 2002. SFAS No. 145 amends existing +authoritative pronouncements to make various technical +corrections, clarify meanings, or describe their applicability +under changed conditions. The provisions of SFAS No. 145, +which the Company adopted January 1, 2003, did not have a +material impact on the Company’s consolidated financial +statements. +The FASB issued Statement of Financial Accounting +Standards No. 146, “Accounting for Costs Associated +with Exit or Disposal Activities,” (“SFAS +No. 146”) in June 2002. SFAS No. 146 is +effective for exit or disposal activities that are initiated +after December 31, 2002. The adoption of SFAS No. 146 +did not have a material impact on the Company’s +consolidated financial statements. +The FASB issued Statement of Financial Accounting +Standards No. 149, “Amendment of Statement 133 on +Derivative Instruments and Hedging Activities,” (“SFAS +No. 149”) in April 2003. SFAS No. 149 amends and +clarifies financial accounting and reporting for derivative +instruments, including certain derivative instruments embedded +in other contracts and for hedging activities under Statement of +Financial Accounting Standards No. 133, “Accounting +for Derivative Instruments and Hedging Activities.” SFAS +No. 149 is effective for existing contracts and new +contracts entered into after June 30, 2003. The provisions +of SFAS No. 149, which the Company adopted on July 1, +2003, did not have a material impact on the Company’s +consolidated financial statements. +The FASB issued Statement of Financial Accounting +Standards No. 150, “Accounting for Certain Financial +Instruments with Characteristics of both Liabilities and +Equity,” (“SFAS No. 150”) in May 2003. SFAS +No. 150 establishes standards for how an issuer classifies +and measures certain financial instruments with characteristics +of both liabilities and equity. The Company has no financial +instruments which are subject to SFAS No. 150. +The FASB issued Interpretation No. 45, +“Guarantor’s Accounting and Disclosure Requirements, +Including Guarantees of Indebtedness of Others,” +(“FIN 45”) which the Company adopted effective +January 1, 2003. FIN 45 requires that upon issuance of +certain types of guarantees, a guarantor recognize and account +for the fair value of the guarantee as a liability. FIN 45 +contains exclusions to this requirement, including the exclusion +of a parent’s guarantee of its subsidiaries’ debt to a +third party. The adoption of FIN 45 did not have a material +impact on the Company’s consolidated financial statements. +The FASB issued Interpretation No. 46, +“Consolidation of Variable Interest Entities,” +(“FIN 46”) which addresses the consolidation of +variable interest entities (“VIEs”) by business +enterprises that are the primary beneficiaries. A VIE is an +entity that does not have sufficient equity investment at risk +to permit it to finance its activities without additional +subordinated financial support, or whose equity investors lack +the characteristics of a controlling financial interest. The +primary beneficiary of a VIE is the enterprise that has the +majority of the risks or rewards associated with the VIE. The +Company believes it has no interests in VIEs that will require +disclosure or consolidation under FIN 46. +Reclassifications — +Certain reclassifications have been made to the 2002 and 2001 +consolidated financial statements in order for them to conform +with the 2003 presentation. +2. Mergers and +Acquisitions +TMBR/Sharp Drilling, +Inc. — On May 26, 2003, +the Company, Patterson-UTI Acquisition, LLC, a wholly-owned +subsidiary of the Company (“Sub”), and TMBR/Sharp +Drilling, Inc., a Texas corporation (“TMBR”), entered +into an Agreement and Plan of Merger, as amended by Amendment +No. 1 to Agreement and Plan of Merger dated as of +December 30, 2003, by and among the same parties (the +“Merger +F-12 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Agreement”), pursuant to which, upon the +satisfaction and completion of the conditions to the merger +contained in the Merger Agreement, including approval of the +Merger Agreement by at least two-thirds of the shareholders of +TMBR, TMBR will merge with and into Sub with Sub being the +surviving company. If the merger is completed, each issued and +outstanding share of common stock, $.10 par value per share, of +TMBR not owned directly or indirectly by the Company or TMBR or +held by TMBR shareholders who validly exercise their +dissenters’ rights under Texas law, will be converted into +the right to receive $9.09 in cash from the Company and 0.312166 +of a share of common stock, $0.01 par value per share, of the +Company (the “Company Common Stock”), for a total of +approximately $40.4 million in cash and approximately +1.39 million shares of Company Common Stock based on the +outstanding shares of TMBR common stock as of January 5, +2004. The Company currently intends to pay the cash portion of +the merger consideration to TMBR shareholders out of funds +available on hand and existing financing facilities. The TMBR +shareholders’ meeting is scheduled for February 11, +2004. +2003 Acquisitions +SEI Drilling +Company — On +January 31, 2003, the Company acquired four land-based +drilling rigs and related equipment from SEI Drilling Company +for $6.0 million in cash. The transaction was accounted for +as an acquisition of assets and the purchase price was allocated +among the assets acquired based on their estimated fair market +values. +Mesa Drilling, +Inc. — On February 7, +2003, the Company acquired three land-based drilling rigs, a +yard, and other related equipment from Mesa Drilling, Inc. and +related entities for $10.5 million in cash. The transaction +was accounted for as an acquisition of assets and the purchase +price was allocated among the assets acquired based on their +estimated fair market values. +Other — On +April 28, 2003, the Company acquired two land-based +drilling rigs for $3.9 million in cash. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +Hexadyne Drilling +Corporation — On +May 30, 2003, the Company acquired seven land-based +drilling rigs and related equipment from Hexadyne Drilling +Corporation for $10.1 million in cash. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +Fort Drilling +LLC — On November 17, +2003, the Company acquired three land-based drilling rigs, a +shop facility, and related equipment from Fort Drilling LLC for +$7.2 million in cash. The transaction was accounted for as +an acquisition of assets and the purchase price was allocated +among the assets acquired based on their estimated fair market +values. +Other — In +addition to the above mentioned acquisitions, the Company spent +approximately $3.1 million on other acquisitions of assets +and costs associated with the acquisitions completed during 2003. +2002 Acquisition +Odin Drilling, +Inc. — On March 21, +2002, the Company acquired five SCR electric land-based drilling +rigs through the acquisition of Odin Drilling, Inc., for a +purchase price of $16.9 million. The purchase price +consisted of 650,000 shares of common stock valued at +$26.06 per share. A deferred tax liability of $4.1 million +was recorded as a result of the transaction. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +2001 Merger and Acquisitions +Cleere Drilling +Company — On +December 21, 2001, the Company acquired 17 drilling +rigs and related equipment from Cleere Drilling Company for an +aggregate purchase price of $25.8 million. The purchase +price +F-13 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +consisted of $13.5 million cash plus +450,000 shares of its common stock and warrants to acquire +an additional 325,000 shares of common stock at an exercise +price of $26.75 per share. The common stock was recorded at +$21.55 per share and the warrants were valued at $8.00 per +underlying share of the Company’s common stock using the +Black-Scholes option valuation model. 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. +UTI Energy +Corp. — On February 4, +2001, Patterson entered into an Agreement and Plan of Merger +with UTI providing for the merger of the two entities. On +May 8, 2001, the stockholders of each company approved the +merger and the merger was consummated. Each outstanding share of +UTI common stock was converted into one share of Patterson +common stock and each option or warrant then outstanding +representing the right to receive UTI common stock was converted +into the right to purchase Patterson-UTI common stock on an +equivalent basis. A total of 37,782,135 shares of common +stock was issued pursuant to the merger and an additional +3,621,079 shares were reserved for issuance under the then +outstanding UTI stock option plans. Additionally, the +stockholders of Patterson approved an increase in the authorized +shares of common stock from 50 million to 200 million +and a name change to “Patterson-UTI Energy, Inc.” +Pursuant to the terms of the Agreement and Plan of Merger and +resolutions adopted by the Company’s Board of Directors, +the Company has agreed to indemnify its directors and officers +and former directors and officers of UTI for acts or omissions +occurring at or prior to the merger with UTI or for certain +liabilities that might occur as a result of the merger with UTI. +The Company incurred $13.1 million in +expenses related to the merger. The expenses consisted of +$5.9 million in merger costs which were primarily related +to professional fees paid to investment banking firms, +attorneys, accountants and commercial printers for their +professional services rendered and $7.2 million in restructuring +costs and related charges incurred as a result of the following: +• +severance costs and related expenses of +$2.8 million, +• +closing of duplicate operational facilities of +$1.6 million, +• +costs of $1.4 million incurred in connection +with changes to the Company’s credit facilities (see +Note 9), and +• +fees and expenses related to the transfer of +licenses and leaseholds, and in some instances the impairment of +such leaseholds, the combination or cancellation of various +service contracts and the renegotiation of certain insurance +policies of $1.4 million. +The merger was treated as a reorganization within +the meaning of Section 368(a) of the Internal Revenue Code of +1986, as amended, and was accounted for as a pooling of +interests for financial accounting purposes. The consolidated +financial statements give retroactive effect to the merger. +Certain adjustments were made in those periods to conform the +previous accounting policies of UTI with those of Patterson. +Jones Drilling +Corporation — On +January 5, 2001, the Company acquired assets consisting of +21 drilling rigs and related equipment and approximately +$2.3 million of net working capital from Jones Drilling +Corporation and three of its affiliated entities. The purchase +price of $33.2 million consisted of 810,070 shares of the +Company’s common stock valued at $26.8125 per share and +$11.3 million cash plus approximately $240,000 in +transaction costs. The transaction was accounted for as a +business combination and the purchase price, net of working +capital acquired, was allocated among the assets acquired based +on their estimated fair market values. +Other — In +January 2001, the Company acquired six drilling rigs, through +three separate transactions, for approximately +$15.7 million cash in aggregate. The transactions were +accounted for as acquisitions of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +F-14 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +3. +Comprehensive Income +The following table illustrates the +Company’s comprehensive income including the effects of +foreign currency translation adjustments for the years ended +December 31, 2003, 2002, and 2001 (in thousands): +2003 +2002 +2001 +Net income +$ +55,326 +$ +2,169 +$ +164,162 +Other comprehensive income: +Foreign currency translation adjustment related +to our Canadian operations +8,773 +457 +(2,326 +) +Unrealized gain on equity securities, net of tax +of $955 in 2003 and $18 in 2002 +1,590 +30 +— +Comprehensive income +$ +65,689 +$ +2,656 +$ +161,836 +4. +Property and Equipment +Property and equipment consisted of the following +at December 31, 2003 and 2002 (in thousands): +2003 +2002 +Drilling rigs and related equipment +$ +1,022,795 +$ +895,125 +Other equipment +65,659 +54,788 +Oil and natural gas properties +57,625 +52,011 +Buildings +11,773 +11,073 +Land +3,684 +3,779 +1,161,536 +1,016,776 +Less accumulated depreciation and depletion +(467,905 +) +(389,042 +) +$ +693,631 +$ +627,734 +5. +Goodwill and Other Intangible Assets +Intangible assets consist primarily of goodwill +arising from business combinations. In accordance with SFAS +No. 142, all of the Company’s intangible assets that +have definite lives are being amortized on a straight-line basis +over their estimated useful lives and goodwill is evaluated to +determine if fair value of the asset has decreased below its +carrying value. At December 31, 2003, the Company evaluated +its goodwill and other intangible assets and determined no +adjustment to impair goodwill and other intangible assets was +necessary. Amortization expense of approximately +$4.7 million recognized during 2001, would not have been +recognized under SFAS No. 142. Goodwill and other +intangible assets as of December 31, 2003 and 2002 are as +follows (in thousands): +2003 +2002 +Goodwill +$ +69,860 +$ +69,860 +Accumulated amortization +(19,661 +) +(19,661 +) +Goodwill, net +50,199 +50,199 +Covenants-not-to-compete and other +$ +1,956 +$ +1,956 +Accumulated amortization +(976 +) +(842 +) +Other intangible assets, net +980 +1,114 +Intangible assets, net +$ +51,179 +$ +51,313 +F-15 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +The amount of goodwill and other intangible +assets as of December 31, 2003 and 2002 assigned to the +contract drilling and drilling and completion fluids operating +segments, the only operating segments that had intangible assets +for such periods, is as follows (in thousands): +2003 +Contract drilling: +Goodwill +$ +56,543 +Accumulated amortization +$ +16,278 +Non-competes and other +$ +1,909 +Accumulated amortization +$ +959 +Drilling and completion fluids: +Goodwill +$ +13,317 +Accumulated amortization +$ +3,383 +Non-competes and other +$ +47 +Accumulated amortization +$ +17 +2002 +Contract drilling: +Goodwill +$ +56,543 +Accumulated amortization +$ +16,278 +Non-competes and other +$ +1,909 +Accumulated amortization +$ +828 +Drilling and completion fluids: +Goodwill +$ +13,317 +Accumulated amortization +$ +3,383 +Non-competes and other +$ +47 +Accumulated amortization +$ +14 +Change in the net carrying amount of goodwill for +the years ended December 31, 2003 and 2002 is as follows (in +thousands): +Drilling & +Completion +Drilling +Fluids +Total +Balance at December 31, 2001 +$ +40,265 +$ +9,934 +$ +50,199 +Changes to goodwill +— +— +— +Balance at December 31, 2002 +40,265 +9,934 +50,199 +Changes to goodwill +— +— +— +Balance at December 31, 2003 +$ +40,265 +$ +9,934 +$ +50,199 +Amortization expense consists of the following +(in thousands): +Years Ended December 31, +2003 +2002 +2001 +Goodwill +$ +— +$ +— +$ +4,665 +Covenants-not-to-compete and other +134 +315 +507 +Total +$ +134 +$ +315 +$ +5,172 +Our weighted average amortization period for +other intangible assets is approximately 13 years. +Estimated amortization expense for these assets is approximately +$97,000 for each of the five succeeding fiscal years. +F-16 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Had SFAS No. 142 been in effect prior to +January 1, 2002, our reported net income and net income per +share would have been as follows (in thousands, except per share +amounts): +Years Ended December 31, +2003 +2002 +2001 +Net income: +Reported +$ +55,326 +$ +2,169 +$ +164,162 +Goodwill amortization +— +— +4,665 +Adjusted +$ +55,326 +$ +2,169 +$ +168,827 +Basic net income per common share: +Reported +$ +0.68 +$ +0.03 +$ +2.15 +Effect of goodwill amortization +— +— +0.06 +Adjusted +$ +0.68 +$ +0.03 +$ +2.21 +Diluted net income per common share: +Reported +$ +0.67 +$ +0.03 +$ +2.07 +Effect of goodwill amortization +— +— +0.06 +Adjusted +$ +0.67 +$ +0.03 +$ +2.13 +6. +Investment in Equity Securities +In 2002, the Company purchased 1,058,673 shares +of the common stock of TMBR, $.10 par value per share, for an +aggregate cash purchase price of $17.6 million, or $16.60 per +share, and approximately $84,000 of additional costs incurred to +acquire the shares. At December 31, 2003, the Company owned +approximately 19.2% of the outstanding shares of TMBR. +The accounting treatment of shares representing +the Company’s investment in the common stock of TMBR has +been affected by the Company’s ability to sell shares +within one year. As of December 31, 2003, the Company no +longer has restrictions on its ability to sell the TMBR shares +within one year. Previously, the restricted shares were +reflected in the balance sheet at cost under the cost method of +accounting in accordance with Accounting Principles Board +Opinion No. 18, “The Equity Method of Accounting for +Investment in Common Stock”. None of the TMBR shares are +restricted from sale within one year. Accordingly, all shares +are classified as Available-for-Sale and are reflected in the +balance sheet at fair value in accordance with SFAS +No. 115. Fair value is determined from publicly quoted +market prices as of the balance sheet date. In accordance with +SFAS No. 115, unrealized gains and losses recorded as a +result of the adjustment to fair value are reflected directly in +stockholders’ equity. +F-17 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +The following table summarizes the Company’s +unrealized gain on its investment in equity securities as of +December 31, 2003 and 2002 (in thousands, except share +amounts): +Common +Unrealized +Shares +Cost +Gain +Total +2003: +TMBR/Sharp Drilling, Inc. +Cost method +— +$ +— +$ +— +$ +— +Available-for-Sale +1,058,673 +17,681 +2,593 +20,274 +1,058,673 +$ +17,681 +$ +2,593 +$ +20,274 +2002: +TMBR/Sharp Drilling, Inc. +Cost method +892,742 +$ +14,833 +$ +— +$ +14,833 +Available-for-Sale +165,931 +2,826 +48 +2,874 +1,058,673 +$ +17,659 +$ +48 +$ +17,707 +7. +Accrued Expenses +Accrued expenses consisted of the following at +December 31, 2003 and 2002 (in thousands): +2003 +2002 +Salaries, wages, payroll taxes and benefits +$ +15,740 +$ +10,573 +Workers’ compensation liability +22,859 +15,516 +Sales, use and other taxes +5,796 +2,712 +Insurance, other than workers’ compensation +1,848 +2,605 +Restructuring and merger related costs +1,000 +1,029 +Other +4,823 +3,078 +$ +52,066 +$ +35,513 +The following table summarizes activity in +restructuring and merger related accrual accounts for the years +ended December 31, 2003 and 2002, respectively (in +thousands): +2003 +2002 +Balance at beginning of year +$ +1,029 +$ +2,200 +Severance costs and related expenses +(21 +) +(324 +) +Closing of duplicate operational facilities +(4 +) +(392 +) +Professional fees +(4 +) +(455 +) +Balance at end of year +$ +1,000 +$ +1,029 +8. +Asset Retirement Obligation +SFAS No. 143 requires that we record a +liability for the estimated costs to be incurred in connection +with the abandonment of oil and natural gas properties in the +future. We recorded a liability of approximately +F-18 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +$1.1 million in the first quarter of 2003 +upon initial adoption of SFAS No. 143. The following table +describes the changes to our asset retirement obligations during +2003: +2003 +Balance at beginning of year +$ +1,056 +Liabilities incurred +173 +Liabilities settled +(100 +) +Accretion expense +34 +Asset retirement obligation at end of year +$ +1,163 +Had SFAS No. 143 been in effect as of +January 1, 2001, the impact on the Company’s results +of operations would have been immaterial for the years ended +December 31, 2002, and 2001 and the asset retirement +obligation would have been $1.1 million, $1.0 million +and $959,000 as of December 31, 2002 and 2001 and +January 1, 2001, respectively. In addition, the cumulative +effect of this change in accounting principle of approximately +$469,000, net of tax, was recorded in the first quarter of 2003. +9. +Notes Payable +There were no amounts outstanding under the +Company’s revolving credit facility at December 31, +2003 or December 31, 2002. The maximum borrowings under +this revolving credit facility were increased from +$90.0 million to $100.0 million in June 2001 and the +term of the facility was also extended to June 2005. A fee of +.375% per annum is assessed on the unused facility amount. The +amount used for letters of credit decreases the borrowing base +of the facility on a dollar-for-dollar basis. The revolving +credit facility calls for periodic interest payments at a +floating rate ranging from LIBOR plus 1.75% to 2.75%. The +applicable rate above LIBOR (1.75% at December 31, 2003) is +based upon our trailing twelve-month earnings before interest +expense, income taxes and depreciation, depletion and +amortization. Assets of the Company secure the facility. The +facility has restrictions customary in financial instruments of +this type including restrictions on certain investments, +acquisitions and loans. The facility has no financial covenants +unless availability under the facility is less than +$20.0 million. The terms of the facility limit the payment +of dividends without the prior written consent of the lenders. +During 2001, the Company repaid +$89.2 million under its existing credit facilities and +other term obligations. The Company incurred expenses of +$448,000 as a result of prepayment penalties and $942,000 +related to deferred financing costs which were unamortized at +the time the debt was extinguished. The penalties and deferred +financing costs were included in restructuring and other charges +in 2001. +10. +Commitments, Contingencies, and Other +Matters +The Company maintains letters of credit in the +aggregate amount of $37.0 million for the benefit of +various insurance companies as collateral for retrospective +premiums and retained losses which may become payable under the +terms of the underlying insurance contracts. These letters of +credit expire variously during each calendar year. No amounts +have been drawn under the letters of credit. +Contingencies — +The Company’s contract services and oil and natural gas +exploration and production operations are subject to inherent +risks, including blowouts, cratering, fire, and explosions which +could result in personal injury or death, suspended drilling +operations, damage to, or destruction of equipment, damage to +producing formations, and pollution or other environmental +hazards. +As a protection against these hazards, the +Company maintains general liability insurance coverage of +$2.0 million per occurrence with $4.0 million of +aggregate coverage and excess liability and umbrella coverages +up to $50.0 million per occurrence and in the aggregate. We +maintain a $1.0 million per occurrence deductible on our +general liability insurance coverage and a $750,000 per +occurrence deductible on our workers’ compensation +insurance coverage. These levels of self-insurance expose us to +increased operating costs and risks. +F-19 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Net income for the year ended December 31, +2002 includes a charge of $4.7 million related to the +financial failure in 2002 of a workers’ compensation +insurance carrier that had provided coverage for the Company in +prior years. +The Company believes it is adequately insured for +public liability and property damage to others with respect to +its operations. However, such insurance may not be sufficient to +protect the Company against liability for all consequences of +well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its rigs; however, it does not +carry insurance against loss of earnings resulting from such +damage or loss. The Company’s lender who has a security +interest in the drilling rigs is named as loss payee on the +physical damage insurance on such rigs. +Westfort Energy LTD and Westfort Energy +(US) LTD f/k/a Canadian Delta, Inc. (“Westfort”), +filed a lawsuit against two Patterson-UTI subsidiaries, +Patterson Petroleum LP, and Patterson-UTI Drilling Company LP, +in the Circuit Court, Rankin County, Mississippi, Case +No. 2002-18. The lawsuit relates to a letter agreement +entered into in July 2000 between Patterson Petroleum LP and +Westfort concerning the drilling of a daywork well in +Mississippi. This lawsuit was filed by Westfort after Patterson +Petroleum LP made demand on Westfort for payment of the contract +drilling services. +The Westfort lawsuit has been dismissed without +prejudice. Westfort filed for bankruptcy in May of 2003. The +Company continues to assert claims against Westfort including +the monies owed Patterson Petroleum LP under the letter +agreement in the amount of approximately $5,075,000. Amounts +deemed uncollectible have been reserved. The Company believes +that it is remote that the outcome of this matter will have a +material adverse effect on the Company’s financial +condition and results of operations. +In this lawsuit, Westfort alleged breach of +contract, fraud, and negligence causes of action. Westfort +sought alleged monetary damages, the return of shares of +Westfort stock, unspecified damages from alleged lost profits, +lost use of income stream, and additional operating expenses, +along with alleged punitive damages to be determined by the +jury, but not less than 25% of the Company’s net worth. The +Company intends to vigorously contest these claims if reasserted +by Westfort. +The Company is also party to various legal +proceedings arising in the normal course of its business. The +Company does not believe that the outcome of these proceedings, +either individually or in the aggregate, will have a material +adverse effect on its financial condition. +Other Matters — +Effective January 29, 2004, the +Company entered into Change in Control Agreements with its +Chairman of the Board, Chief Executive Officer, President and +Chief Operating Officer, two Senior Vice Presidents and Chief +Financial Officer (the “Key Employees”). Each Change +in Control Agreement generally has a three-year term with +automatic twelve month renewals unless the Company notifies the +Key Employee at least ninety days before the end of such renewal +period that the term will not be extended. If a change in +control of the Company occurs during the term of the agreement +and the Key Employee’s employment is terminated (i) by +the Company other than for cause or other than automatically as +a result of death, disability or retirement or (ii) by the +Key Employee for good reason (as those terms are defined in the +Change in Control Agreements), then the Key Employee shall be +entitled to, among other things, +• +bonus payment equal to the greater of the highest +bonus paid after the Change in Control Agreement was entered +into and the average of the two annual bonuses earned in the two +fiscal years immediately preceding a change in control (such +bonus payment prorated for the portion of the fiscal year +preceding the termination date); +• +a payment equal to 2.5 times (in the case of the +Chairman of the Board, Chief Executive Officer and President and +Chief Operating Officer) or 1.5 times (in the case of the Senior +Vice Presidents and the Chief Financial Officer) of the sum of +(i) the highest annual salary in effect for such Key +Employee and (ii) the average of the three annual bonuses +earned by the Key Employee for the three fiscal years preceding +the termination date; and +F-20 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +• +continued coverage under the Company’s +welfare plans for up to three years (in the case of the Chairman +of the Board, Chief Executive Officer and President and Chief +Operating Officer) or two years (in the case of the Senior Vice +Presidents and the Chief Financial Officer). +Each Change in Control Agreement provides the Key +Employee with a full gross-up payment for any excise taxes +imposed on payments and benefits received under the Change in +Control Agreements or otherwise, including other taxes that may +be imposed as a result of the gross-up payment. +11. +Stockholders’ Equity +During March 2002, the Company issued 650,000 +shares of its common stock as consideration for the acquisition +of Odin Drilling, Inc. (see Note 2). The common stock was +valued at $26.06 per share, its fair market value on the date +the terms of the transaction were agreed upon. +During December 2001, the Company issued 450,000 +shares of its common stock and warrants to acquire an additional +325,000 shares at an exercise price of $26.75 per share, as +partial consideration for the acquisition of 17 drilling rigs +and related equipment from Cleere Drilling Company. The common +stock was recorded at $21.55 per share and the warrants were +valued at $8.00 per underlying share of common stock using the +Black-Scholes option valuation model (see Note 2). +On May 8, 2001, pursuant to the merger +between Patterson and UTI, the Company’s stockholders +approved an amendment to the Company’s charter increasing +the number of authorized shares of the Company’s common +stock to 200 million. +During January 2001, the Company issued 810,070 +shares of its common stock as partial consideration for the +acquisition of Jones Drilling Corporation and certain assets +owned by its related entities (see Note 2). The common +stock was valued at $26.8125 per share, its fair market value on +the date of the transaction. +12. +Stock Options and Warrants +Employee and Non-Employee Director Stock +Option Plans — The Company +has seven stock option plans of which three have shares +available for grant. The remaining four plans are dormant and +the Company does not intend to grant any further options under +such plans. At December 31, 2003, the Company’s stock +option plans were as follows: +Options +Options +Authorized +Options +Available +Plan Name +For Grant +Outstanding +For Grant +Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (“1997 Plan”)(1)(3) +8,250,000 +4,503,838 +1,949,537 +Amended and Restated Patterson-UTI Energy, Inc. +2001 Long-Term Incentive Plan (“2001 Plan”)(2) +1,000,000 +846,737 +25,694 +Amended and Restated Non-Employee Director Stock +Option Plan of Patterson-UTI Energy, Inc. (“Non-Employee +Director Plan”)(1) +600,000 +150,000 +292,500 +Patterson-UTI Energy, Inc. Non-Employee +Directors’ Stock Option Plan, as amended (“1995 +Non-Employee Director Plan”) +120,000 +16,000 +— +1997 Stock Option Plan of DSI Industries, Inc. +(“DSI Plan”)(1) +— +1,608 +— +Amended and Restated Patterson-UTI Energy, Inc. +1996 Employee Stock Option Plan (“1996 Plan”)(1) +— +238,900 +— +Patterson-UTI Energy, Inc., 1993 Incentive Stock +Plan, as amended (“1993 Plan”) +2,800,000 +368,675 +— +F-21 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +(1) +Plan was assumed by the Company as a part of the +merger between Patterson and UTI. +(2) +Plan is for the benefit of employees of the +Company, other than officers and directors of the Company. +(3) +Plan is for the benefit of employees of the +Company, including officers and directors of the Company. +The Company’s active plans are the 1997 +Plan, the 2001 Plan and the Non-Employee Director Plan. A +summary of each of these plans is set forth below. +1997 Plan +• +Administered by the Compensation Committee of the +Board of Directors. +• +All employees including officers and employee +directors are eligible for awards. +• +Vesting schedule is set by the Compensation +Committee, however, typically options vest over 3 or +5 years. +• +The Compensation Committee sets the term of the +option except that no Incentive Stock Option (“ISO”) +can have a term of longer than 10 years. Typically options +granted under the plan have a term of 10 years. +• +The options granted under the plan, unless +otherwise stated in the grant thereof, vest upon a change of +control as defined in the plan. Options granted to non-executive +employees typically do not vest upon a change of control. +• +All options granted under the plan are granted +with an exercise price equal to or greater than the fair market +value of the Company’s common stock at the time the option +is granted. +• +Although the plan allows for awards of tandem and +independent stock appreciation rights, restricted stock and +performance awards, no such awards have been granted. +• +During 2003, the Company increased the options +authorized for grant from 6,000,000 to 8,250,000. +2001 Plan +The terms and conditions of the 2001 Plan are +identical to the 1997 Plan except as follows: +• +Officers and directors of the Company are not +eligible for grants of options under the 2001 Plan. +• +No ISO’s may be awarded under the 2001 Plan. +• +Unless the grant states otherwise, options +granted under the 2001 Plan do not vest upon a change of control +of the Company. +Non-Employee Director Plan +• +Administered by the Compensation Committee of the +Board of Directors. +• +All options vest upon the first anniversary of +the option grant. +• +Each director receives options to purchase 20,000 +shares upon becoming a director of the Company and options to +purchase 10,000 shares on December 31 of each subsequent +year in which the director serves as a director of the Company. +• +The exercise price of the options is the fair +market value of the Company’s common stock on the date of +grant. +Of the four dormant plans administered by the +Company, two of the plans (the 1993 Plan and the 1995 +Non-Employee Director Plan) were plans of the Company prior to +the merger of Patterson and UTI and two of the plans (the DSI +Plan and the 1996 Plan) were plans of UTI. +1995 Non-Employee Director +Plan — Options granted under +the 1995 Non-Employee Director Plan vest on the first +anniversary of the option grant. 1995 Non-Employee Director Plan +options have five year terms. +F-22 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +All options were granted with an exercise price +equal to the fair market value of the Company’s common +stock at the time of grant. +DSI Plan — +The options granted under the DSI plan typically vested at a +rate of 33% per year with ten year terms. All options were +granted with an exercise price equal to the fair market value of +the Company’s common stock at the time of grant. +1996 +Plan — The options granted +under the 1996 plan vested over one, four and five years as +dictated by the Compensation Committee. These options had terms +of five and ten years as dictated by the Compensation Committee. +All options were granted with an exercise price equal to the +fair market value of the Company’s common stock at the time +of grant. +1993 +Plan — Options granted under +the 1993 Plan, typically had terms of 10 years and vested +over five years in 20% increments beginning at the end of the +first year. These options vest in the event of a change of +control as defined in the plan. All options were granted with an +exercise price equal to the fair market value of the +Company’s common stock at the time of grant. +Additional Options — +In July 2001, the Compensation +Committee granted to each of two non-employee directors of the +Company an option to purchase 12,000 shares of the +Company’s common stock. These options vested on +November 6, 2001 and terminate four years later on +November 5, 2005. The exercise price of each of the options +was $28.625, which was in excess of the fair market value of the +Company’s common stock on the date of grant. +A summary of the status of the Company’s +stock options issued as of December 31, 2003, 2002, and +2001 and the changes during each of the years then ended are +presented below (in thousands, except weighted average exercise +price): +2003 +2002 +2001 +No. of +Weighted +No. of +Weighted +No. of +Weighted +Shares of +Average +Shares of +Average +Shares of +Average +Underlying +Exercise +Underlying +Exercise +Underlying +Exercise +Options +Price +Options +Price +Options +Price +Outstanding at beginning of year +6,139 +$ +17.61 +6,596 +$ +10.40 +5,488 +$ +7.57 +Granted +915 +32.48 +2,149 +26.77 +2,103 +16.19 +Exercised +(868 +) +11.84 +(2,457 +) +6.41 +(805 +) +5.26 +Surrendered/Expired +(48 +) +19.97 +(149 +) +15.32 +(190 +) +14.39 +Outstanding at end of year +6,138 +$ +20.62 +6,139 +$ +17.61 +6,596 +$ +10.40 +Exercisable at end of year +2,986 +$ +16.29 +2,395 +$ +10.88 +4,110 +$ +7.52 +The following table summarizes information about +stock options outstanding at December 31, 2003: +Options Outstanding +Options Exercisable +Weighted +Average +Weighted +Remaining +Weighted +Average +Number +Contracted +Average +Number +Exercise +Range of Exercise Prices +Outstanding +Life +Exercise Price +Exercisable +Prices +$3.125 to $5.00 +832,681 +5.17 +$ +4.75 +810,548 +$ +4.74 +$5.01 to $10.00 +118,545 +4.36 +$ +9.35 +118,545 +$ +9.35 +$10.01 to $15.00 +201,958 +3.65 +$ +14.20 +201,958 +$ +14.20 +$15.01 to $20.00 +1,852,074 +7.43 +$ +16.02 +812,097 +$ +16.09 +$20.01 to $25.00 +47,500 +3.88 +$ +22.88 +47,500 +$ +22.88 +$25.01 to $30.00 +2,125,000 +8.50 +$ +26.72 +949,912 +$ +26.59 +$30.01 to $32.93 +960,000 +8.76 +$ +32.41 +45,000 +$ +31.07 +6,137,758 +7.49 +$ +20.62 +2,985,560 +$ +16.29 +F-23 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Pro Forma Stock-Based Compensation +Disclosure — Pro forma +information in accordance with SFAS No. 123 regarding +net income and earnings per share, as described in Note 1, +has been determined as if the Company had accounted for its +employee stock options under the fair value method as defined in +that statement. The fair value of each stock option granted is +estimated on the date of grant using the Black-Scholes option +valuation model with the following weighted-average assumptions +for grants in 1996 through 2003 respectively; dividend yield of +0.00%; risk-free interest rates are different for each grant and +range from 2.81% 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 and 52.05% for all 2003 +grants. The effects of applying SFAS No. 123 in this pro +forma disclosure are not indicative of future amounts. SFAS No. +123 does not apply to awards prior to 1996. +Stock Purchase +Warrants — In December 2001, +the Company issued 325,000 warrants exercisable at $26.75 +per share as partial consideration for the purchase of +17 drilling rigs and related equipment from Cleere Drilling +Company (see Note 2). The warrants were fully exercisable +at the date of issuance. If not exercised, the warrants will +expire on December 21, 2004. +In June 2000, the Company issued 127,000 warrants +exercisable at $22 per share as partial consideration for the +purchase of eight drilling rigs and related equipment from High +Valley Drilling, Inc. The warrants were fully exercisable at the +date of issuance and none remain outstanding at +December 31, 2003. +Tabular +Summary — The following +table summarizes information regarding the Company’s stock +options and warrants granted under the provisions of the +aforementioned plans as well as stock options and warrants +issued pursuant to certain transactions described in +Notes 2 and 11: +Weighted +Average +Shares +Exercise Price +Granted +2003 +915,000 +$ +32.48 +2002 +2,148,500 +26.77 +2001 +2,428,500 +17.60 +Exercised +2003 +970,782 +$ +12.91 +2002 +2,481,486 +6.56 +2001 +804,581 +5.26 +Surrendered +2003 +47,562 +$ +19.97 +2002 +149,205 +15.32 +2001 +190,473 +14.39 +Outstanding at Year End +2003 +6,462,758 +$ +20.93 +2002 +6,566,101 +18.13 +2001 +7,048,292 +11.36 +Exercisable at Year End +2003 +3,310,560 +$ +17.32 +2002 +2,822,726 +13.11 +2001 +4,562,259 +9.29 +F-24 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +13. Leases +The Company incurred rent expense, consisting +primarily of daily rental charges for the use of drilling +equipment, of $8.6 million, $5.7 million, and +$5.9 million, for the years 2003, 2002, and 2001, +respectively. The Company’s obligations under +non-cancelable operating lease agreements are not material to +the Company’s operations. +14. Income +Taxes +Components of the income tax provision applicable +for federal, state and foreign income taxes are as follows (in +thousands): +2003 +2002 +2001 +Federal income tax expense (benefit): +Current +$ +13,856 +$ +(18,064 +) +$ +82,417 +Deferred +14,509 +21,687 +10,887 +28,365 +3,623 +93,304 +State income tax expense (benefit): +Current +1,214 +(1,811 +) +4,294 +Deferred +76 +1,117 +661 +1,290 +(694 +) +4,955 +Foreign income tax expense (benefit): +Current +18 +(2,003 +) +1,062 +Deferred +2,689 +744 +3,012 +2,707 +(1,259 +) +4,074 +Total: +Current +15,088 +(21,878 +) +87,773 +Deferred +17,274 +23,548 +14,560 +Total income tax expense +$ +32,362 +$ +1,670 +$ +102,333 +The difference between the statutory federal +income tax rate and the effective income tax rate is summarized +as follows: +2003 +2002 +2001 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.5 +2.8 +1.9 +Permanent differences +0.8 +5.7 +1.3 +Other, net +(0.6 +) +— +0.2 +Effective tax rate +36.7 +% +43.5 +% +38.4 +% +In assessing the realizability of deferred tax +assets, management considers whether it is more likely than not +that some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income, and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2003 to be +realized as a result of the reversal during the carryforward +period of existing taxable temporary differences giving rise to +deferred tax liabilities and the generation of taxable income in +the carryforward period; therefore, no valuation allowance is +necessary. +F-25 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +The tax effect of significant temporary +differences representing deferred tax assets and liabilities and +changes therein were as follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +January 1, +2003 +Change +2002 +Change +2001 +Change +2001 +Deferred tax assets: +Net operating loss carryforwards +$ +— +$ +— +$ +— +$ +— +$ +— +$ +(5,850 +) +$ +5,850 +Investment tax credit carryforwards +— +— +— +— +— +(469 +) +469 +Workers’ compensation allowance +10,107 +2,934 +7,173 +2,663 +4,510 +3,951 +559 +AMT credit carryforwards +602 +— +602 +— +602 +(3,770 +) +4,372 +Other +5,740 +(1,775 +) +7,515 +3,880 +3,635 +(1,160 +) +4,795 +Deferred tax assets +16,449 +1,159 +15,290 +6,543 +8,747 +(7,298 +) +16,045 +Deferred tax liabilities: +Property and equipment basis difference +(143,490 +) +(16,484 +) +(127,006 +) +(34,147 +) +(92,859 +) +(16,005 +) +(76,854 +) +Net deferred tax liability +$ +(127,041 +) +$ +(15,325 +) +$ +(111,716 +) +$ +(27,604 +) +$ +(84,112 +) +$ +(23,303 +) +$ +(60,809 +) +The alternative minimum tax credit may be carried +forward indefinitely. +15. Employee +Benefits +The Company maintains a 401(k) plan for all +eligible employees. The Company’s operating results include +expenses of $1.5 million in 2003, and $2.1 million in +2002 and 2001 for the Company’s discretionary contributions +to the plan. +16. Business +Segments +The Company conducts its business through four +distinct operating segments: contract drilling of oil and +natural gas wells, pressure pumping services and drilling and +completion fluids services to operators in the oil and natural +gas industry, and the exploration, development, acquisition and +production of oil and natural gas. Each of these segments +represents a distinct type of business based upon the type and +nature of services and products offered. These segments have +separate management teams which report to the Company’s +chief executive officer and have distinct and identifiable +revenues and expenses. +Contract +Drilling — The Company +markets its contract drilling services to major and independent +oil and natural gas operators. The Company owns 343 drilling +rigs, of which 226 operated in 2003. Currently, 143 of the +drilling rigs are based in West Texas and New Mexico, 56 in +South Texas, 42 in the Ark-La-Tex region and Mississippi, 70 in +the Mid-Continent region, 16 in the Rocky Mountain region, and +16 in Western Canada. +Pressure +Pumping — The Company +provides pressure pumping services primarily in the Appalachian +Basin. Pressure pumping services consist primarily of well +stimulation and cementing for the completion of new wells and +remedial work on existing wells. Well stimulation involves +processes inside a well designed to enhance the flow of oil, +natural gas, or other desired substances from the well. +Cementing is the process of inserting material between the hole +and the pipe to center and stabilize the pipe in the hole. +Drilling and Completion +Fluids — The Company +provides drilling fluids, completion fluids, and related +services to oil and natural gas operators in West Texas, +Southeast New Mexico, South Texas, East Texas, Oklahoma, the +Gulf Coast regions of Texas and Louisiana, and the Gulf of +Mexico. Drilling and completion +F-26 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +fluids are used by oil and natural gas operators +during the drilling process to control pressure when drilling +oil and natural gas wells. The drilling fluids operations were +added by the Company during 1998 with its acquisition of two +companies with operations in Texas, New Mexico, Oklahoma, and +Colorado. Our services were expanded to include completion +fluids in October 2000 with the acquisition of the drilling and +completion fluids division of Ambar, Inc., which had operations +in the coastal areas of Texas, Louisiana, and in the Gulf of +Mexico. +Oil and Natural +Gas — The Company is engaged +in the development, exploration, acquisition, and production of +oil and natural gas. +The following tables summarize selected financial +information relating to our business segments (in thousands): +Years Ended December 31, +2003 +2002 +2001 +Revenues: +Contract drilling +$ +639,694 +$ +410,295 +$ +839,931 +Pressure pumping +46,083 +32,996 +39,600 +Drilling and completion fluids +69,230 +69,943 +94,456 +Oil and natural gas +21,163 +14,723 +15,988 +Total revenues +$ +776,170 +$ +527,957 +$ +989,975 +Income before income taxes: +Contract drilling +$ +75,666 +$ +7,607 +$ +274,514 +Pressure pumping +10,442 +6,090 +12,649 +Drilling and completion fluids +(1,960 +) +(278 +) +3,842 +Oil and natural gas +7,784 +3,945 +756 +Corporate and other +(7,194 +) +(9,266 +) +(11,444 +) +Merger costs +— +— +(5,943 +) +Restructuring and other charges(a) +2,452 +(4,700 +) +(7,202 +) +Interest income +1,116 +1,110 +2,080 +Interest expense +(292 +) +(532 +) +(3,142 +) +Other +143 +(137 +) +385 +Income before income taxes +$ +88,157 +$ +3,839 +$ +266,495 +(a) +Restructuring and other charges relate to +decisions of the executive management group regarding corporate +strategy, credit risk, loss contingencies and restructuring +activities. Due to the non-operating nature of these decisions, +the related charges have been separately presented and excluded +from the results of specific segments. These charges are +primarily related to the contract drilling segment. +F-27 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Years Ended December 31, +2003 +2002 +2001 +Identifiable assets: +Contract drilling +$ +801,109 +$ +694,020 +$ +681,700 +Pressure pumping +46,763 +35,084 +29,473 +Drilling and completion fluids +30,860 +34,687 +41,724 +Oil and natural gas +33,494 +20,854 +15,398 +Corporate and other (a) +163,604 +157,864 +101,347 +Total assets +$ +1,075,830 +$ +942,509 +$ +869,642 +Depreciation, depletion and amortization: +Contract drilling +$ +84,379 +$ +80,500 +$ +72,797 +Pressure pumping +3,774 +2,803 +1,895 +Drilling and completion fluids +2,319 +2,216 +2,644 +Oil and natural gas +7,082 +5,251 +8,505 +Corporate and other +444 +446 +318 +Total depreciation, depletion and amortization +$ +97,998 +$ +91,216 +$ +86,159 +Capital expenditures: +Contract drilling +$ +95,175 +$ +68,516 +$ +150,788 +Pressure pumping +10,524 +7,399 +7,756 +Drilling and completion fluids +912 +1,571 +4,937 +Oil and natural gas +10,484 +6,357 +7,956 +Corporate and other +— +— +5,320 +Total capital expenditures +$ +117,095 +$ +83,843 +$ +176,757 +(a) +Corporate assets primarily include cash on hand +managed by the parent corporation and certain deferred federal +income tax assets. +F-28 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +17. +Quarterly Financial Information +Quarterly financial information for the years +ended December 31, 2003 and 2002 is as follows (in +thousands): +1st +2nd +3rd +4th +Quarter +Quarter +Quarter +Quarter +Total +2003 +Operating revenues +$ +165,239 +$ +195,624 +$ +207,015 +$ +208,292 +$ +776,170 +Operating income +9,844 +19,153 +27,354 +30,839 +87,190 +Net income +5,756 +12,052 +17,113 +20,405 +55,326 +Earnings per share: +Basic +$ +0.07 +$ +0.15 +$ +0.21 +$ +0.25 +$ +0.68 +Diluted +$ +0.07 +$ +0.15 +$ +0.21 +$ +0.25 +$ +0.67 +2002 +Operating revenues +$ +128,223 +$ +125,363 +$ +133,495 +$ +140,876 +$ +527,957 +Operating income (loss) +6,428 +(6,591 +) +683 +2,878 +3,398 +Net income (loss) +3,935 +(3,845 +) +249 +1,830 +2,169 +Earnings (loss) per share: +Basic +$ +0.05 +$ +(0.05 +) +$ +0.00 +$ +0.02 +$ +0.03 +Diluted +$ +0.05 +$ +(0.05 +) +$ +0.00 +$ +0.02 +$ +0.03 +18. +Concentrations of Credit Risk +Financial instruments, which potentially subject +the Company to concentrations of credit risk, consist primarily +of demand deposits, temporary cash investments, and trade +receivables. +The Company believes that it places its demand +deposits and temporary cash investments with high credit quality +financial institutions. At December 31, 2003 and 2002, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2003 +2002 +Deposits in FDIC and SIPC-insured institutions +under $100,000. +$ +(3,326 +) +$ +1,711 +Deposits in FDIC and SIPC-insured institutions +over $100,000. +112,226 +90,464 +108,900 +92,175 +Less outstanding checks and other reconciling +items +(8,417 +) +(10,021 +) +Cash and cash equivalents +$ +100,483 +$ +82,154 +Concentrations of credit risk with respect to +trade receivables are primarily focused on companies involved in +the exploration and development of oil and natural gas +properties. The concentration is somewhat mitigated by the +diversification of customers for which the Company provides +drilling services. As is general industry practice, the Company +generally does not require customers to provide collateral. No +significant losses from individual contracts were experienced +during the years ended December 31, 2003, 2002, or 2001. We +recognized bad debt expense for 2003, 2002, and 2001 of +$259,000, $320,000, and $2.0 million, respectively. +The carrying values of cash and cash equivalents, +marketable securities, and trade receivables approximate fair +value due to the short-term maturity of these assets. +19. Related Party +Transactions +Use of +Assets — In 2001, we leased +a 1981 Beech King-Air 90 airplane owned by SSI Oil and Gas, +Inc., an entity beneficially owned 50% by Cloyce A. +Talbott, Patterson-UTI’s Chief Executive Officer, and +directly +F-29 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +owned 50% by A. Glenn Patterson, +Patterson-UTI’s President/Chief Operating Officer. Under +the terms of the lease, we paid a monthly rental of $9,200, the +costs of fuel, insurance, taxes and maintenance of the aircraft. +Such amounts totaled approximately $212,000 for the year ended +December 31, 2001. +Joint Operation of Oil and Natural Gas +Properties — The Company +operates certain oil and natural gas properties in which certain +of our affiliated persons have participated, either individually +or through entities they control, in the prospects or properties +in which we have an interest. These participations, which have +been on a working interest basis, have been in prospects or +properties originated or acquired by Patterson-UTI. At +December 31, 2003, affiliated persons were working interest +owners in 236 of the 260 wells operated by Patterson-UTI. Sales +of working interests are made by Patterson-UTI to reduce its +economic risk in the properties. Sales were made by +Patterson-UTI at its cost, comprised of Patterson-UTI’s +costs of acquiring and preparing the working interests for sale. +These costs were paid by the working interest owners on a pro +rata basis based upon their working interest ownership +percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests +were sold to unaffiliated persons. The affiliated persons earned +oil and natural gas production revenue (net of royalty) of +$11.1 million, $6.9 million, and $8.3 million +from these properties in 2003, 2002, and 2001, respectively. +These persons or entities were in turn billed for joint +operating costs (including drilling and other development +expenses) of $7.9 million, $5.5 million, and +$5.9 million incurred in 2003, 2002, and 2001, +respectively. This activity resulted in a net receivable from +the affiliated persons of approximately $17,000 at +December 31, 2003 and a net payable to the affiliated +persons of approximately $466,000 at December 31, 2002. +Other — In +2003, 2002 and 2001, we paid approximately $740,000, $279,000 +and $387,000, respectively, to TMP Truck and Trailer LP +(“TMP”), an entity owned by Thomas M. Patterson +(son of A. Glenn Patterson), for certain equipment and +metal fabrication services. Purchases from TMP were at current +market prices. +In 2003, we paid approximately $209,000 to Melco +Services (“Melco”) for dirt contracting services and +$59,000 to L&N Transportation (“L&N”) for +water hauling services. Both entities are owned by Lance D. +Nelson, brother of Jonathan D. Nelson, Patterson-UTI’s +Chief Financial Officer. Purchases from Melco and L&N were +at current market prices. +20. +Supplementary Oil and Natural Gas Reserve +Information and Related Data (Unaudited) +Oil and Natural Gas Expenditures and +Capitalized Costs: +Gross oil and natural gas expenditures by the +Company for the years ended December 31, 2003, 2002 and +2001 are summarized below (in thousands): +2003 +2002 +2001 +Property acquisition costs +$ +1,120 +$ +905 +$ +3,813 +Exploration costs +7,572 +6,267 +6,788 +Development costs +1,531 +845 +1,354 +$ +10,223 +$ +8,017 +$ +11,955 +The aggregate amount of capitalized costs of oil +and natural gas properties as of December 31, 2003, 2002 +and 2001 is comprised of the following (in thousands): +2003 +2002 +2001 +Proved properties +$ +50,481 +$ +44,849 +$ +43,500 +Accumulated depreciation and depletion +(42,405 +) +(35,684 +) +(35,828 +) +$ +8,076 +$ +9,165 +$ +7,672 +F-30 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Results of operations for oil and natural +gas producing activities: +2003 +2002 +2001 +Oil and natural gas sales +$ +19,058 +$ +12,738 +$ +13,842 +Gain on sale of oil and natural gas properties +571 +303 +213 +19,629 +13,041 +14,055 +Costs and expenses: +Lease operating and production costs +3,479 +3,068 +3,393 +Exploration costs including dry holes and +abandonments +1,073 +785 +1,212 +Depreciation and depletion +5,638 +4,633 +7,417 +Impairment of oil and natural gas properties +1,444 +727 +1,088 +11,634 +9,213 +13,110 +Results of operations for oil and natural gas +producing activities, before taxes +$ +7,995 +$ +3,828 +$ +945 +Oil and natural gas reserve +quantities: +The following table sets forth information with +respect to quantities of net proved developed oil and natural +gas reserves and changes in those reserves for the years ended +December 31, 2003, 2002, and 2001 (in thousands). The +quantities were estimated by an independent petroleum engineer. +The Company’s proved developed oil and natural gas reserves +are located entirely within the United States. +Oil (Bbls) +Gas (Mcf) +Estimated quantity, January 1, 2001 +1,129 +3,880 +Revision in previous estimates +16 +609 +Extensions, discoveries and other additions +175 +1,862 +Sales of reserves +(1 +) +— +Production +(272 +) +(1,717 +) +Estimated quantity, January 1, 2002 +1,047 +4,634 +Revision in previous estimates +145 +2,103 +Extensions, discoveries and other additions +331 +1,420 +Sales of reserves +(12 +) +(110 +) +Production +(284 +) +(1,807 +) +Estimated quantity, January 1, 2003 +1,227 +6,240 +Revision in previous estimates +87 +(1,123 +) +Extensions, discoveries and other additions +149 +2,446 +Sales of reserves +(27 +) +(244 +) +Production +(289 +) +(2,052 +) +Estimated quantity, January 1, 2004 +1,147 +5,267 +Estimates of our proved reserves and future net +revenues are determined based on various assumptions such as oil +and natural gas prices, operating costs, reservoir performance, +and economic conditions. The oil and natural gas prices and +operating cost assumptions were based on the actual prices and +costs in effect as of the date of such estimates. These +assumptions are held constant throughout the life of the +properties, except operating costs are adjusted for contractual +escalations. Our reserve engineer estimates the assumptions +relating to reservoir performance and economic conditions using +information available and industry experience. The oil and +natural gas prices used to value our reserves as of +December 31, 2003 were $32.52 per Bbl of +F-31 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +oil and $6.19 per Mcf of natural gas. Estimates +of reserves and production performance are subjective and may +change materially as actual production information becomes +available. +Standardized measure of future net cash +flows of proved developed oil and natural gas reserves, +discounted at 10% per annum (in thousands): +Years Ended December 31, +2003 +2002 +2001 +Future gross revenues +$ +70,894 +$ +68,165 +$ +32,674 +Future development and production costs +(23,021 +) +(22,149 +) +(13,077 +) +Future income tax expense(a) +(15,155 +) +(15,964 +) +(5,110 +) +Future net cash flows +32,718 +30,052 +14,487 +Discount at 10% per annum +(8,768 +) +(8,952 +) +(3,773 +) +Standardized measure of discounted future net +cash flows +$ +23,950 +$ +21,100 +$ +10,714 +(a) +Future income taxes are computed by applying the +statutory tax rate to future net cash flows less the tax basis +of the properties and net operating loss attributable to oil and +natural gas operations and investment tax credit carryforwards +as of year-end; statutory depletion and tax credits applicable +to future oil and natural gas-producing activities are also +considered in the income tax computation. +Changes in the standardized measure of net +cash flows of proved developed oil and natural gas reserves +discounted at 10% per annum (in thousands): +Years Ended December 31, +2003 +2002 +2001 +Standardized measure at beginning of year +$ +21,100 +$ +10,714 +$ +16,640 +Sales and transfers of oil and natural gas +produced, net of production costs +(11,362 +) +(8,342 +) +(8,684 +) +Net changes in sales price and future production +and development costs +4,718 +4,888 +(10,670 +) +Extensions, discoveries and improved recovery, +less related costs +10,052 +6,017 +2,870 +Sales of minerals-in-place +(2,017 +) +(30 +) +(1 +) +Revision of previous quantity estimates +(2,976 +) +4,315 +(2,824 +) +Accretion of discount +3,547 +1,531 +2,440 +Other +101 +(9,358 +) +13,588 +Net change in income taxes +787 +11,365 +(2,645 +) +Standardized measure at end of year +$ +23,950 +$ +21,100 +$ +10,714 +F-32 +Table of Contents +PATTERSON-UTI ENERGY, INC. +SCHEDULE II — VALUATION +AND QUALIFYING ACCOUNTS +Additions(1) +Charged to +Acquired +Beginning +Costs and +through +Ending +Description +Balance +Expenses +Acquisition +Deductions(2) +Balance +(In thousands) +Year Ended December 31, 2003 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +3,144 +$ +259 +$ +— +$ +1,270 +$ +2,133 +Year Ended December 31, 2002 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +4,021 +$ +320 +$ +— +$ +1,197 +$ +3,144 +Year Ended December 31, 2001 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +3,462 +$ +2,045 +$ +— +$ +1,486 +$ +4,021 +(1) +Net of recoveries. +(2) +Uncollectible accounts written off. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 +or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI +Energy, Inc. has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ CLOYCE A. TALBOTT +Cloyce A. Talbott +Chief Executive Officer +Date: February 4, 2004 +Pursuant to the requirements of the Securities +Exchange Act of 1934, this report has been signed by the +following persons on behalf of Patterson-UTI Energy, Inc. and in +the capacities indicated as of February 4, 2004. +Signature +Title +/s/ MARK S. SIEGEL +Mark S. Siegel +Chairman of the Board +/s/ CLOYCE A. TALBOTT +Cloyce A. Talbott +(Principal Executive Officer) +Chief Executive Officer and Director +/s/ A. GLENN PATTERSON +A. Glenn Patterson +President, Chief Operating Officer and Director +/s/ KENNETH N. BERNS +Kenneth N. Berns +Senior Vice President and Director +/s/ JONATHAN D. NELSON +Jonathan D. Nelson +(Principal Accounting Officer) +Vice President, Chief Financial Officer, +Secretary and Treasurer +/s/ ROBERT C. GIST +Robert C. Gist +Director +/s/ CURTIS W. HUFF +Curtis W. Huff +Director +/s/ TERRY H. HUNT +Terry H. Hunt +Director +/s/ KENNETH R. PEAK +Kenneth R. Peak +Director +/s/ NADINE C. SMITH +Nadine C. Smith +Director +Table of Contents +EXHIBIT INDEX +2.1 +Agreement and Plan of Merger, dated as of +May 26, 2003, by and among Patterson-UTI Energy, Inc., +Patterson-UTI Acquisition, LLC and TMBR/Sharp Drilling, Inc.(1) +2.2 +Amendment No. 1 to Agreement and Plan of +Merger, dated as of December 30, 2003, by and among +Patterson-UTI Energy, Inc., Patterson-UTI Acquisition, LLC and +TMBR/Sharp Drilling, Inc.(2) +3.1 +Restated Certificate of Incorporation, as +amended.(3) +3.2 +Amended and Restated Bylaws.(4) +4.1 +Rights Agreement dated January 2, 1997, +between Patterson Energy, Inc. and Continental Stock +Transfer & Trust Company.(5) +4.2 +Amendment to Rights Agreement dated as of +October 23, 2001.(6) +4.3 +Restated Certificate of Incorporation, as amended +(See Exhibit 3.1) +4.4 +Registration Rights Agreement with Bear, Stearns +and Co. Inc., dated March 25, 1994, as assigned by REMY +Capital Partners III, L.P.(4) +4.5 +Patterson-UTI Energy, Inc. 1993 Stock Incentive +Plan, as amended.(7)* +4.6 +Patterson-UTI Energy, Inc. Non-Employee +Directors’ Stock Option Plan, as amended.(8)* +4.7 +Amended and Restated Patterson-UTI Energy, Inc. +2001 Long-Term Incentive Plan.(9)* +4.8 +Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan.(3)* +4.9 +Amended and Restated Patterson-UTI Energy, Inc. +Non-Employee Director Stock Option Plan.(3)* +4.10 +Amended and Restated Patterson-UTI Energy, Inc. +1996 Employee Stock Option Plan.(10)* +4.11 +1997 Stock Option Plan of DSI Industries, +Inc.(11)* +4.12 +Stock Option Agreement dated July 20, 2001 +between Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.).(4)* +10.1 +For additional material contracts, see +Exhibits 4.1, 4.2 and 4.4 through 4.11. +10.2 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel.* +10.3 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and A. Glenn Patterson.* +10.4 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott.* +10.5 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns.* +10.6 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Jonathan D. Nelson.* +10.7 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III.* +10.8 +Model Form Operating Agreement.(12) +10.9 +Form of Drilling Bid Proposal and Footage +Drilling Contract.(12) +10.10 +Form of Turnkey Drilling Agreement.(12) +14.1 +Patterson-UTI Energy, Inc. Code of Business +Conduct and Ethics for Senior Financial Executives. +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Accountants — +PricewaterhouseCoopers LLP. +23.2 +Consent of Independent Petroleum +Engineer — M. Brian Wallace, P.E. +31.1 +Certification of Chief Executive Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +31.2 +Certification of Chief Financial Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +32.1 +Certification of Chief Executive Officer and +Chief Financial Officer pursuant to 18 USC +Section 1350, as adopted pursuant to Section 906 of +the Sarbanes-Oxley Act of 2002. +(1) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K of TMBR/Sharp Drilling, Inc. +filed on May 27, 2003. +(2) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K filed on December 31, +2003. +Table of Contents +(3) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended June 30, +2003, filed on July 28, 2003. +(4) +Incorporated herein by reference to Item 14, +“Exhibits, Financial Statement Schedules and Reports on +Form 8-K” to Annual Report on Form 10-K for the +fiscal year ended December 31, 2001, filed on +March 19, 2002. +(5) +Incorporated herein by reference to Item 2, +“Exhibits” to Registration Statement on Form 8-A +filed on January 14, 1997. +(6) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended September 30, +2001, filed on October 31, 2001. +(7) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-47917) filed on March 13, 1998. +(8) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-39471) filed on November 4, 1997. +(9) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File No. 333-60470) +filed on November 27, 2002. +(10) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60466) filed on July 25, 2001. +(11) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60470) filed on July 25, 2001. +(12) +Incorporated herein by reference to Item 27, +“Exhibits” to Registration Statement on Form SB-2 +(File No. 33-68058-FW) filed on August 30, 1993. +* +Management Contract or Compensatory Plan +identified as required by Item 15(a)(3) of Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/filing_metadata.csv b/raw/filings/0000889900/2003/0000950134-04-001065/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e7a4d7aa2f5df6201fb7639c3fb778c1ea47b8e4 --- /dev/null +++ b/raw/filings/0000889900/2003/0000950134-04-001065/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2004-02-04,2003-12-31,2004-02-04T16:12:36.000Z,0000950134-04-001065,d12235e10vk.htm,FORM 10-K,1705629,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013404001065/d12235e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095013404001065/,2003,2003,1 diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/item1.txt b/raw/filings/0000889900/2003/0000950134-04-001065/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/item13.txt b/raw/filings/0000889900/2003/0000950134-04-001065/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..2de07ab4ff0da1d01fa012ef238a4ef2ed4ca0ae --- /dev/null +++ b/raw/filings/0000889900/2003/0000950134-04-001065/item13.txt @@ -0,0 +1,5 @@ +Item 13. +Certain Relationships and Related +Transactions. +The information required by this Item is +incorporated herein by reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/item9a.txt b/raw/filings/0000889900/2003/0000950134-04-001065/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ccfb76ec89454d51609f5b04ffcec322c0251891 --- /dev/null +++ b/raw/filings/0000889900/2003/0000950134-04-001065/item9a.txt @@ -0,0 +1,33 @@ +Item 9A. +Controls and Procedures. +As of the end of the period covered by this +Annual Report on Form 10-K, the effectiveness of our +disclosure controls and procedures (as defined in +Rules 13a-15(e) and 15d-15(e) promulgated under the +Securities Exchange Act of 1934) was evaluated by our +management, with the participation of our Chief Executive +Officer, Cloyce A. Talbott (principal executive officer), +and our Vice President, Chief Financial Officer, Secretary and +Treasurer, Jonathan D. Nelson (principal financial officer). +Messrs. Talbott and Nelson have concluded that our +disclosure controls and procedures are effective, as of the end +of the period covered by this Report, to help ensure that +information we are required to disclose in reports that we file +with the SEC is accumulated and communicated to management and +recorded, processed, summarized and reported within the time +periods prescribed by the SEC. +There were no changes in our internal control +over financial reporting that occurred during our last fiscal +quarter (the quarter ended December 31, 2003) that have +materially affected, or are reasonably likely to materially +affect, our internal control over financial reporting. +36 +Table of Contents +PART III +The information required by Part III is +omitted from this Report because Patterson-UTI will file a +definitive proxy statement pursuant to Regulation 14A of +the Securities Exchange Act of 1934 no later than 120 days +after the end of the fiscal year covered by this Report and +certain information included therein is incorporated herein by +reference. \ No newline at end of file diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/rp_note.txt b/raw/filings/0000889900/2003/0000950134-04-001065/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..3b07cb953e78cfed6ea03c7f70553a229fb03bc2 --- /dev/null +++ b/raw/filings/0000889900/2003/0000950134-04-001065/rp_note.txt @@ -0,0 +1,678 @@ +19. Related Party +Transactions +Use of +Assets — In 2001, we leased +a 1981 Beech King-Air 90 airplane owned by SSI Oil and Gas, +Inc., an entity beneficially owned 50% by Cloyce A. +Talbott, Patterson-UTI’s Chief Executive Officer, and +directly +F-29 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +owned 50% by A. Glenn Patterson, +Patterson-UTI’s President/Chief Operating Officer. Under +the terms of the lease, we paid a monthly rental of $9,200, the +costs of fuel, insurance, taxes and maintenance of the aircraft. +Such amounts totaled approximately $212,000 for the year ended +December 31, 2001. +Joint Operation of Oil and Natural Gas +Properties — The Company +operates certain oil and natural gas properties in which certain +of our affiliated persons have participated, either individually +or through entities they control, in the prospects or properties +in which we have an interest. These participations, which have +been on a working interest basis, have been in prospects or +properties originated or acquired by Patterson-UTI. At +December 31, 2003, affiliated persons were working interest +owners in 236 of the 260 wells operated by Patterson-UTI. Sales +of working interests are made by Patterson-UTI to reduce its +economic risk in the properties. Sales were made by +Patterson-UTI at its cost, comprised of Patterson-UTI’s +costs of acquiring and preparing the working interests for sale. +These costs were paid by the working interest owners on a pro +rata basis based upon their working interest ownership +percentage. The price at which working interests were sold to +affiliated persons was the same price at which working interests +were sold to unaffiliated persons. The affiliated persons earned +oil and natural gas production revenue (net of royalty) of +$11.1 million, $6.9 million, and $8.3 million +from these properties in 2003, 2002, and 2001, respectively. +These persons or entities were in turn billed for joint +operating costs (including drilling and other development +expenses) of $7.9 million, $5.5 million, and +$5.9 million incurred in 2003, 2002, and 2001, +respectively. This activity resulted in a net receivable from +the affiliated persons of approximately $17,000 at +December 31, 2003 and a net payable to the affiliated +persons of approximately $466,000 at December 31, 2002. +Other — In +2003, 2002 and 2001, we paid approximately $740,000, $279,000 +and $387,000, respectively, to TMP Truck and Trailer LP +(“TMP”), an entity owned by Thomas M. Patterson +(son of A. Glenn Patterson), for certain equipment and +metal fabrication services. Purchases from TMP were at current +market prices. +In 2003, we paid approximately $209,000 to Melco +Services (“Melco”) for dirt contracting services and +$59,000 to L&N Transportation (“L&N”) for +water hauling services. Both entities are owned by Lance D. +Nelson, brother of Jonathan D. Nelson, Patterson-UTI’s +Chief Financial Officer. Purchases from Melco and L&N were +at current market prices. +20. +Supplementary Oil and Natural Gas Reserve +Information and Related Data (Unaudited) +Oil and Natural Gas Expenditures and +Capitalized Costs: +Gross oil and natural gas expenditures by the +Company for the years ended December 31, 2003, 2002 and +2001 are summarized below (in thousands): +2003 +2002 +2001 +Property acquisition costs +$ +1,120 +$ +905 +$ +3,813 +Exploration costs +7,572 +6,267 +6,788 +Development costs +1,531 +845 +1,354 +$ +10,223 +$ +8,017 +$ +11,955 +The aggregate amount of capitalized costs of oil +and natural gas properties as of December 31, 2003, 2002 +and 2001 is comprised of the following (in thousands): +2003 +2002 +2001 +Proved properties +$ +50,481 +$ +44,849 +$ +43,500 +Accumulated depreciation and depletion +(42,405 +) +(35,684 +) +(35,828 +) +$ +8,076 +$ +9,165 +$ +7,672 +F-30 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +Results of operations for oil and natural +gas producing activities: +2003 +2002 +2001 +Oil and natural gas sales +$ +19,058 +$ +12,738 +$ +13,842 +Gain on sale of oil and natural gas properties +571 +303 +213 +19,629 +13,041 +14,055 +Costs and expenses: +Lease operating and production costs +3,479 +3,068 +3,393 +Exploration costs including dry holes and +abandonments +1,073 +785 +1,212 +Depreciation and depletion +5,638 +4,633 +7,417 +Impairment of oil and natural gas properties +1,444 +727 +1,088 +11,634 +9,213 +13,110 +Results of operations for oil and natural gas +producing activities, before taxes +$ +7,995 +$ +3,828 +$ +945 +Oil and natural gas reserve +quantities: +The following table sets forth information with +respect to quantities of net proved developed oil and natural +gas reserves and changes in those reserves for the years ended +December 31, 2003, 2002, and 2001 (in thousands). The +quantities were estimated by an independent petroleum engineer. +The Company’s proved developed oil and natural gas reserves +are located entirely within the United States. +Oil (Bbls) +Gas (Mcf) +Estimated quantity, January 1, 2001 +1,129 +3,880 +Revision in previous estimates +16 +609 +Extensions, discoveries and other additions +175 +1,862 +Sales of reserves +(1 +) +— +Production +(272 +) +(1,717 +) +Estimated quantity, January 1, 2002 +1,047 +4,634 +Revision in previous estimates +145 +2,103 +Extensions, discoveries and other additions +331 +1,420 +Sales of reserves +(12 +) +(110 +) +Production +(284 +) +(1,807 +) +Estimated quantity, January 1, 2003 +1,227 +6,240 +Revision in previous estimates +87 +(1,123 +) +Extensions, discoveries and other additions +149 +2,446 +Sales of reserves +(27 +) +(244 +) +Production +(289 +) +(2,052 +) +Estimated quantity, January 1, 2004 +1,147 +5,267 +Estimates of our proved reserves and future net +revenues are determined based on various assumptions such as oil +and natural gas prices, operating costs, reservoir performance, +and economic conditions. The oil and natural gas prices and +operating cost assumptions were based on the actual prices and +costs in effect as of the date of such estimates. These +assumptions are held constant throughout the life of the +properties, except operating costs are adjusted for contractual +escalations. Our reserve engineer estimates the assumptions +relating to reservoir performance and economic conditions using +information available and industry experience. The oil and +natural gas prices used to value our reserves as of +December 31, 2003 were $32.52 per Bbl of +F-31 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND +SUBSIDIARIES +NOTES TO CONSOLIDATED +FINANCIAL STATEMENTS — (Continued) +oil and $6.19 per Mcf of natural gas. Estimates +of reserves and production performance are subjective and may +change materially as actual production information becomes +available. +Standardized measure of future net cash +flows of proved developed oil and natural gas reserves, +discounted at 10% per annum (in thousands): +Years Ended December 31, +2003 +2002 +2001 +Future gross revenues +$ +70,894 +$ +68,165 +$ +32,674 +Future development and production costs +(23,021 +) +(22,149 +) +(13,077 +) +Future income tax expense(a) +(15,155 +) +(15,964 +) +(5,110 +) +Future net cash flows +32,718 +30,052 +14,487 +Discount at 10% per annum +(8,768 +) +(8,952 +) +(3,773 +) +Standardized measure of discounted future net +cash flows +$ +23,950 +$ +21,100 +$ +10,714 +(a) +Future income taxes are computed by applying the +statutory tax rate to future net cash flows less the tax basis +of the properties and net operating loss attributable to oil and +natural gas operations and investment tax credit carryforwards +as of year-end; statutory depletion and tax credits applicable +to future oil and natural gas-producing activities are also +considered in the income tax computation. +Changes in the standardized measure of net +cash flows of proved developed oil and natural gas reserves +discounted at 10% per annum (in thousands): +Years Ended December 31, +2003 +2002 +2001 +Standardized measure at beginning of year +$ +21,100 +$ +10,714 +$ +16,640 +Sales and transfers of oil and natural gas +produced, net of production costs +(11,362 +) +(8,342 +) +(8,684 +) +Net changes in sales price and future production +and development costs +4,718 +4,888 +(10,670 +) +Extensions, discoveries and improved recovery, +less related costs +10,052 +6,017 +2,870 +Sales of minerals-in-place +(2,017 +) +(30 +) +(1 +) +Revision of previous quantity estimates +(2,976 +) +4,315 +(2,824 +) +Accretion of discount +3,547 +1,531 +2,440 +Other +101 +(9,358 +) +13,588 +Net change in income taxes +787 +11,365 +(2,645 +) +Standardized measure at end of year +$ +23,950 +$ +21,100 +$ +10,714 +F-32 +Table of Contents +PATTERSON-UTI ENERGY, INC. +SCHEDULE II — VALUATION +AND QUALIFYING ACCOUNTS +Additions(1) +Charged to +Acquired +Beginning +Costs and +through +Ending +Description +Balance +Expenses +Acquisition +Deductions(2) +Balance +(In thousands) +Year Ended December 31, 2003 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +3,144 +$ +259 +$ +— +$ +1,270 +$ +2,133 +Year Ended December 31, 2002 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +4,021 +$ +320 +$ +— +$ +1,197 +$ +3,144 +Year Ended December 31, 2001 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +3,462 +$ +2,045 +$ +— +$ +1,486 +$ +4,021 +(1) +Net of recoveries. +(2) +Uncollectible accounts written off. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 +or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI +Energy, Inc. has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ CLOYCE A. TALBOTT +Cloyce A. Talbott +Chief Executive Officer +Date: February 4, 2004 +Pursuant to the requirements of the Securities +Exchange Act of 1934, this report has been signed by the +following persons on behalf of Patterson-UTI Energy, Inc. and in +the capacities indicated as of February 4, 2004. +Signature +Title +/s/ MARK S. SIEGEL +Mark S. Siegel +Chairman of the Board +/s/ CLOYCE A. TALBOTT +Cloyce A. Talbott +(Principal Executive Officer) +Chief Executive Officer and Director +/s/ A. GLENN PATTERSON +A. Glenn Patterson +President, Chief Operating Officer and Director +/s/ KENNETH N. BERNS +Kenneth N. Berns +Senior Vice President and Director +/s/ JONATHAN D. NELSON +Jonathan D. Nelson +(Principal Accounting Officer) +Vice President, Chief Financial Officer, +Secretary and Treasurer +/s/ ROBERT C. GIST +Robert C. Gist +Director +/s/ CURTIS W. HUFF +Curtis W. Huff +Director +/s/ TERRY H. HUNT +Terry H. Hunt +Director +/s/ KENNETH R. PEAK +Kenneth R. Peak +Director +/s/ NADINE C. SMITH +Nadine C. Smith +Director +Table of Contents +EXHIBIT INDEX +2.1 +Agreement and Plan of Merger, dated as of +May 26, 2003, by and among Patterson-UTI Energy, Inc., +Patterson-UTI Acquisition, LLC and TMBR/Sharp Drilling, Inc.(1) +2.2 +Amendment No. 1 to Agreement and Plan of +Merger, dated as of December 30, 2003, by and among +Patterson-UTI Energy, Inc., Patterson-UTI Acquisition, LLC and +TMBR/Sharp Drilling, Inc.(2) +3.1 +Restated Certificate of Incorporation, as +amended.(3) +3.2 +Amended and Restated Bylaws.(4) +4.1 +Rights Agreement dated January 2, 1997, +between Patterson Energy, Inc. and Continental Stock +Transfer & Trust Company.(5) +4.2 +Amendment to Rights Agreement dated as of +October 23, 2001.(6) +4.3 +Restated Certificate of Incorporation, as amended +(See Exhibit 3.1) +4.4 +Registration Rights Agreement with Bear, Stearns +and Co. Inc., dated March 25, 1994, as assigned by REMY +Capital Partners III, L.P.(4) +4.5 +Patterson-UTI Energy, Inc. 1993 Stock Incentive +Plan, as amended.(7)* +4.6 +Patterson-UTI Energy, Inc. Non-Employee +Directors’ Stock Option Plan, as amended.(8)* +4.7 +Amended and Restated Patterson-UTI Energy, Inc. +2001 Long-Term Incentive Plan.(9)* +4.8 +Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan.(3)* +4.9 +Amended and Restated Patterson-UTI Energy, Inc. +Non-Employee Director Stock Option Plan.(3)* +4.10 +Amended and Restated Patterson-UTI Energy, Inc. +1996 Employee Stock Option Plan.(10)* +4.11 +1997 Stock Option Plan of DSI Industries, +Inc.(11)* +4.12 +Stock Option Agreement dated July 20, 2001 +between Patterson-UTI Energy, Inc. and Kenneth R. Peak (a +non-employee director of Patterson-UTI Energy, Inc.).(4)* +10.1 +For additional material contracts, see +Exhibits 4.1, 4.2 and 4.4 through 4.11. +10.2 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel.* +10.3 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and A. Glenn Patterson.* +10.4 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott.* +10.5 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns.* +10.6 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Jonathan D. Nelson.* +10.7 +Patterson-UTI Energy, Inc. Change in Control +Agreement, effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III.* +10.8 +Model Form Operating Agreement.(12) +10.9 +Form of Drilling Bid Proposal and Footage +Drilling Contract.(12) +10.10 +Form of Turnkey Drilling Agreement.(12) +14.1 +Patterson-UTI Energy, Inc. Code of Business +Conduct and Ethics for Senior Financial Executives. +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Accountants — +PricewaterhouseCoopers LLP. +23.2 +Consent of Independent Petroleum +Engineer — M. Brian Wallace, P.E. +31.1 +Certification of Chief Executive Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +31.2 +Certification of Chief Financial Officer pursuant +to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act +of 1934, as amended. +32.1 +Certification of Chief Executive Officer and +Chief Financial Officer pursuant to 18 USC +Section 1350, as adopted pursuant to Section 906 of +the Sarbanes-Oxley Act of 2002. +(1) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K of TMBR/Sharp Drilling, Inc. +filed on May 27, 2003. +(2) +Incorporated herein by reference to +Exhibit 2.1 to Form 8-K filed on December 31, +2003. +Table of Contents +(3) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended June 30, +2003, filed on July 28, 2003. +(4) +Incorporated herein by reference to Item 14, +“Exhibits, Financial Statement Schedules and Reports on +Form 8-K” to Annual Report on Form 10-K for the +fiscal year ended December 31, 2001, filed on +March 19, 2002. +(5) +Incorporated herein by reference to Item 2, +“Exhibits” to Registration Statement on Form 8-A +filed on January 14, 1997. +(6) +Incorporated herein by reference to Item 6, +“Exhibits and Reports on Form 8-K” to +Form 10-Q for the quarterly period ended September 30, +2001, filed on October 31, 2001. +(7) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-47917) filed on March 13, 1998. +(8) +Incorporated herein by reference to Item 8, +“Exhibits” to Registration Statement on Form S-8 +(File No. 333-39471) filed on November 4, 1997. +(9) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File No. 333-60470) +filed on November 27, 2002. +(10) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60466) filed on July 25, 2001. +(11) +Incorporated herein by reference to Item 8, +“Exhibits” to Post-Effective Amendment No. 1 to +Registration Statement on Form S-8 (File +No. 333-60470) filed on July 25, 2001. +(12) +Incorporated herein by reference to Item 27, +“Exhibits” to Registration Statement on Form SB-2 +(File No. 33-68058-FW) filed on August 30, 1993. +* +Management Contract or Compensatory Plan +identified as required by Item 15(a)(3) of Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2003/0000950134-04-001065/rpt_disclosure.txt b/raw/filings/0000889900/2003/0000950134-04-001065/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2004/0000950134-05-003775/rp_note.txt b/raw/filings/0000889900/2004/0000950134-05-003775/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/filing.txt b/raw/filings/0000889900/2006/0000950134-07-004227/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e47e656f2a32b767305c38d5368a565fadb26f4a --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/filing.txt @@ -0,0 +1,7774 @@ +10-K +1 +d43932e10vk.htm +FORM 10-K +e10vk +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. +20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2006 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, +Inc. +(Exact name of registrant as +specified in its charter) +Delaware +75-2504748 +(State or other jurisdiction +of +incorporation or organization) +(I.R.S. Employer +Identification No.) +4510 Lamesa Highway, Snyder, +Texas +79549 +(Address of principal executive +offices) +(Zip Code) +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 defined in Rule 405 of the Securities +Act. Yes þ or +No o +Indicate by check mark if the registrant is not required to file +reports pursuant to Section 13 or Section 15(d) of the +Act. Yes o or +No þ +Indicate by check mark whether the registrant (1) has filed +all reports required to be filed by Section 13 or 15(d) of +the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant +was required to file such reports), and (2) has been +subject to such filing requirements for the past +90 days. Yes þ No o +Indicate by check mark if disclosure of delinquent filers +pursuant to Item 405 of +Regulation S-K +is not contained herein, and will not be contained, to the best +of the registrant’s knowledge, in definitive proxy or +information statements incorporated by reference in +Part III of this +Form 10-K +or any amendment to this +Form 10-K. þ +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, or a non-accelerated +filer. See definition of “accelerated filer and large +accelerated filer” in +Rule 12b-2 +of the Exchange Act. (Check one): +Large +accelerated filer þ +Accelerated +filer o +Non-accelerated +filer o +Indicate by check mark whether the registrant is a shell company +(as defined in +Rule 12b-2 +of the +Act). Yes o No þ +The aggregate market value of the voting and non-voting common +equity held by non-affiliates of the registrant as of +June 30, 2006, the last business day of the +registrant’s most recently completed second fiscal quarter, +was $4,638,987,745, calculated by reference to the closing price +of $28.31 for the common stock on the Nasdaq National Market on +that date. +As of February 22, 2007, the registrant had outstanding +156,543,478 shares of common stock, $.01 par value, +its only class of voting common stock. +Documents incorporated by reference: +Definitive Proxy Statement for the 2007 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,” in Part I of this Report. +PART I +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file 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 operator 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, +• +Arkansas, +• +Louisiana, +• +Mississippi, +• +Colorado, +• +Utah, +• +Wyoming, +• +Montana, +• +North Dakota, +• +South Dakota, and +• +Western Canada (Alberta, British Columbia and Saskatchewan). +As of December 31, 2006, we had a drilling fleet that +consisted of 336 currently marketable land-based 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. A drilling rig is considered +currently marketable at a point in time if it is operating or +can be made ready to operate without significant capital +expenditures. We also have a substantial inventory of drilling +rig components and equipment which may be used in the activation +of additional drilling rigs or as replacement parts for +marketable rigs. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast +1 +region of Louisiana. Drilling and completion fluids are used by +oil and natural gas operators during the drilling process to +control pressure when drilling oil and natural gas wells. We are +also engaged in the development, exploration, acquisition and +production of oil and natural gas. Our oil and natural gas +operations are focused primarily in producing regions of West +and South Texas, Southeastern New Mexico, Utah and Mississippi. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas development, exploration, acquisition and +production. +All of our industry segments had operating profits in 2006, 2005 +and 2004. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for +financial information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2006, we had 336 currently marketable +land-based drilling rigs which were based in the following +regions: +• +107 in the Permian Basin region (West Texas and Southeastern New +Mexico), +• +50 in South Texas, +• +44 in the Ark-La-Tex region and Mississippi, +• +67 in the Mid-Continent region (Oklahoma and North Central +Texas), +• +48 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana, North Dakota and South Dakota), and +• +20 in Western Canada (Alberta, British Columbia and +Saskatchewan). +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Fifty-six of these drilling rigs are SCR electric rigs and 280 +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. We also have a substantial inventory of drilling rig +components and equipment which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with: +• +engines, +• +drawworks or hoists, +• +derricks or masts, +• +pumps to circulate the drilling fluid, +• +blowout preventers, +• +drill string (pipe), and +• +other related equipment. +2 +Over time, components on a drilling rig are replaced or rebuilt. +We spend significant funds each year on an ongoing program to +modify and upgrade our drilling rigs to ensure that our drilling +equipment is well maintained and competitive. We have spent +$1 billion during the last three years on capital +improvements to modify and upgrade our drilling rigs. During +fiscal years 2006, 2005 and 2004, we spent approximately +$531 million, $329 million and $141 million, +respectively, on these capital improvements. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. We use our rigs for developmental and +exploratory drilling, and they are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of: +• +drill pipe, +• +bits, +• +replacement parts and other related rig equipment, +• +fuel, and +• +qualified personnel, +some of which have been in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Typically, the contracts are short-term to +drill a single well or a series of wells. 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 and 2006. These long-term +contracts provide for the use of drilling rigs for fixed periods +of time during which multiple wells are drilled. During 2006, +our average number of days to drill a well was approximately +21 days. We may continue to enter into long-term contracts +when considered beneficial 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. +Most drilling contracts are subject to termination by the +customer on short notice. We generally indemnify our customers +against claims by our employees and claims that might arise from +surface pollution caused by spills of fuel, lubricants and other +solvents within our control. The customers generally indemnify +us against claims that might arise from other surface and +subsurface pollution, except claims that might arise from our +gross negligence. +The contracts provide for payment on a daywork, footage, or +turnkey basis, or a combination thereof. In each case, we +provide the rig and crews. Our bid for each contract depends +upon: +• +location, depth and anticipated complexity of the well, +• +on-site +drilling conditions, +• +equipment to be used, +• +estimated risks involved, +• +estimated duration of the job, +• +availability of drilling rigs, and +• +other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We sometimes receive a +lower rate when the drilling rig is moving, or when drilling +operations are +3 +interrupted or restricted by adverse weather conditions or other +conditions beyond our control. Daywork contracts typically +provide separately for mobilization of the drilling rig. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor assumes certain risks +associated with loss of the well from fire, blowouts and other +risks. 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 specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also assume +certain risks associated with drilling the well such as fires, +blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed scope of the work has +been completed, which requires us to make larger up-front +working capital commitments prior to receiving payments under a +turnkey drilling contract. Under a turnkey contract, we have the +opportunity to improve our profits if the drilling process goes +as expected and there are no complications or time delays. +However, given the increased exposure we have under a turnkey +contract, profits can be significantly reduced and losses can be +incurred if complications or delays occur during the drilling +process. Turnkey contracts generally involve the highest degree +of risk among the three different types of drilling contracts: +daywork, footage and turnkey. 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. +Revenues by Contract Type — Information +regarding our revenues by contract type for the last three years +follows: +Year Ended December 31, +Type of Revenues +2006 +2005 +2004 +Daywork +100 +% +98 +% +88 +% +Footage +0 +1 +6 +Turnkey +0 +1 +6 +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2006 +2005 +2004 +Average rigs operating(1) +296 +276 +211 +Number of rigs operated +331 +307 +259 +Number of wells drilled +5,050 +4,594 +3,534 +Number of operating days +108,221 +100,591 +77,355 +(1) +A rig is operating when it is drilling, being moved, assembled, +dismantled or otherwise earning revenue under contract. +4 +Drilling Rigs and Related Equipment — Certain +drilling rig information with respect to rigs that were +currently marketable as of December 31, 2006 follows: +Depth Rating (Ft.) +Mechanical +Electric +Total +5,000 to 9,999 +33 +— +33 +10,000 to 11,999 +49 +3 +52 +12,000 to 13,999 +60 +5 +65 +14,000 to 15,999 +120 +21 +141 +16,000 to 30,000 +18 +27 +45 +Totals +280 +56 +336 +At December 31, 2006, we owned and operated 336 trucks and +439 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and Western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the well bore. Generally, Appalachian Basin wells require +cementing services before production commences. The cementing +process inserts material between the wall of the well bore and +the casing to center and stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2006 follows: +• +36 cement pumper trucks, +• +35 fracturing pumper trucks, +• +37 nitrogen pumper trucks, +• +20 blender trucks, +• +7 bulk acid trucks, +• +44 bulk cement trucks, +• +14 bulk nitrogen trucks, +• +3 bulk nitrogen trailers, +• +40 bulk sand trucks, +• +21 connection trucks, +• +3 acid pumper trucks, and +• +10 sand pneumatic trucks. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +Southeastern New Mexico, Oklahoma and the Gulf Coast region of +Louisiana. We serve our offshore customers through six +stockpoint facilities located along the Gulf of +5 +Mexico in Texas and Louisiana and our land-based customers +through eleven stockpoint facilities in Texas, Louisiana, +Oklahoma and New Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to ensure that the products and systems are applied +effectively to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +Raw Materials — Our drilling and completion +fluids 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 — We own and operate a +barite grinding facility with two barite grinding mills in +Houma, Louisiana. This facility allows us to grind raw barite +into the powder additive used in drilling fluids. +Other Equipment — We operate 20 trucks and 83 +trailers and lease another 33 trucks which are used to transport +drilling and completion fluids and related equipment. +Oil and +Natural Gas Operations +General — We are engaged in the development, +exploration, acquisition and production of oil and natural gas. +Our oil and natural gas business operates primarily in producing +regions of West and South Texas, Southeastern New Mexico, Utah +and Mississippi. We significantly expanded our oil and natural +gas operations in 2004 through our acquisition of TMBR/Sharp +Drilling, Inc. (“TMBR”). The oil and natural gas +assets acquired in the acquisition of TMBR included both proved +reserves and undeveloped properties. +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 2006, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping Businesses — +Our land drilling and pressure pumping businesses are highly +competitive. At times, available land drilling rigs and pressure +pumping equipment exceed the demand for such equipment. The +equipment can also be moved from one market to another in +response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +6 +Oil and Natural Gas Business — There is +substantial competition for the acquisition of oil and natural +gas leases suitable for development and exploration and for +experienced personnel. Our competitors in this business include: +• +major integrated oil and natural gas operators, +• +independent oil and natural gas operators, and +• +drilling and production purchase programs. +Our ability to increase our oil and natural gas reserves in the +future is directly dependent upon our ability to select, acquire +and develop suitable prospects. Many of our competitors have +facilities and financial and human resources greater than ours. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. Several state and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We use operating and disposal practices that are standard in the +industry. However, hydrocarbons and other materials may have +been disposed of or released in or under properties currently or +formerly owned or operated by us or our predecessors. In +addition, some of these properties have been operated by third +parties over whom we have no control of their treatment of +hydrocarbon and other materials or the manner in which they may +have disposed of or released such materials. +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +7 +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a “major source.” As a +consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting +process may require capital expenditures in order to comply with +permit limits. +Risks and +Insurance +Our operations are subject to the many hazards inherent in the +drilling business, including: +• +accidents at the work location, +• +blow-outs, +• +cratering, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +8 +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for public liability +and property damage to others with respect to our operations. +However, such insurance may not be sufficient to protect us +against liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance coverage for major physical damage to +our drilling rigs. However, we do not carry insurance against +loss of earnings resulting from such damage. In view of the +difficulties that may be encountered in renewing such insurance +at reasonable rates, no assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications may not be supported by +adequate insurance maintained by the customer. +Employees +We had approximately 9,000 full-time employees at +December 31, 2006. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our pressure pumping division in Appalachia +and our drilling operations in Canada are subject to slow +periods of activity during the Spring thaw. In addition, our +drilling operations in Canada are subject to slow periods of +activity during the Fall. +Raw +Materials and Subcontractors +We use many suppliers of raw materials and services. These +materials and services have historically been available, +although there is no assurance that such materials and services +will continue to be available on favorable terms or at all. We +also utilize numerous independent subcontractors from various +trades. +9 +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 filings with the SEC, press releases and reports to +stockholders. These forward-looking statements are made pursuant +to the “Safe Harbor” provisions of the Private +Securities Litigation Reform Act of 1995. These statements +include, without limitation, statements relating to liquidity, +financing of operations, sources and sufficiency of funds and +impact of inflation. The words “believes,” +“budgeted,” “expects,” “project,” +“will,” “could,” “may,” +“plans,” “intends,” “strategy,” or +“anticipates,” and similar expressions are used to +identify our forward-looking statements. We do not undertake to +update, revise, or correct any of our forward-looking +information. +We include the following cautionary statement in accordance with +the “Safe Harbor” provisions of the Private Securities +Litigation Reform Act of 1995 for any forward-looking statement +made by us, or on our behalf. The factors identified in this +cautionary statement are important factors (but not necessarily +all of the important factors) that could cause actual results to +differ materially from those expressed in any forward-looking +statement made by us, or on our behalf. Where any such +forward-looking statement includes a statement of the +assumptions or bases underlying such forward-looking statement, +we caution that, while we believe such assumptions or bases to +be reasonable and make them in good faith, assumed facts or +bases almost always vary from actual results. The differences +between assumed facts or bases and actual results can be +material, depending upon the circumstances. +Where, in any forward-looking statement, we express an +expectation or belief as to the future results, such expectation +or belief is expressed in good faith and believed to have a +reasonable basis. However, there can be no assurance that the +statement of expectation or belief will result, or be achieved +or accomplished. Taking this into account, the following are +identified as important risk factors currently applicable to, or +which could readily be applicable to, us: +We are +Dependent on the Oil and Natural Gas Industry and Market Prices +for Oil and Natural Gas. Declines in Oil and Natural Gas Prices +Have Adversely Affected Our Operations. +Our revenue, profitability and rate of growth are substantially +dependent upon prevailing prices for oil and natural gas. For +many years, oil and natural gas prices and, therefore, the level +of drilling, exploration, development and production, have been +extremely volatile. Prices are affected by: +• +market supply and demand, +• +international military, political and economic +conditions, and +• +the ability of the Organization of Petroleum Exporting +Countries, commonly known as OPEC, to set and maintain +production and price targets. +All of these factors are beyond our control. The average market +price of natural gas has improved from $3.36 in 2002 to $6.94 in +2006 resulting in an increase in demand for our drilling +services. Our average number of rigs operating increased from +126 in 2002 to 296 in 2006. We expect oil and natural gas prices +to continue to be volatile and to affect our financial condition +and operations and ability to access sources of capital. A +significant decrease in market prices for natural gas would +likely 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 Affects +Our Profit 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 difficulty sustaining profit margins during +the downturn periods. +10 +In addition to adverse effects that future declines in demand +could have on us, ongoing factors which could adversely affect +utilization rates and pricing, even in an environment of high +oil and natural gas prices and increased drilling activity, +include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new drilling rigs. +As a result of an increase in drilling activity and increased +prices for drilling services, construction of new drilling rigs +has increased significantly. We cannot predict either the future +level of demand for our contract drilling services or future +conditions in the oil and natural gas contract drilling business. +Shortages +of Drill Pipe, Replacement Parts and Other Related Rig Equipment +Adversely Affects Our Operating Results. +During periods of increased demand for drilling services, the +industry has experienced shortages of drill pipe, replacement +parts and other related rig equipment. These shortages can cause +the price of these items to increase significantly and require +that orders for the items be placed well in advance of expected +use. These price increases and delays in delivery may require us +to increase capital and repair expenditures in our contract +drilling segment. Severe shortages could impair our ability to +operate our drilling rigs. +The +Various Business Segments in Which We Operate Are Highly +Competitive with Excess Capacity which may Adversely Affect Our +Operating Results. +Our land drilling and pressure pumping businesses are highly +competitive. At times, available land drilling rigs and pressure +pumping equipment exceed the demand for such equipment. This +excess capacity has resulted in substantial competition for +drilling and pressure pumping contracts. The fact that drilling +rigs and pressure pumping equipment are mobile and can be moved +from one market to another in response to market conditions +heightens the competition in the industry. +We believe that price competition for drilling and pressure +pumping contracts will continue for the foreseeable future due +to the existence of available rigs and pressure pumping +equipment. +In recent years, many drilling and pressure pumping companies +have consolidated or merged with other companies. Although this +consolidation has decreased the total number of competitors, we +believe the competition for drilling and pressure pumping +services will continue to be intense. +The drilling and completion fluids services industry is highly +competitive. Price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Labor +Shortages Adversely Affect Our Operating Results. +During periods of increasing demand for contract drilling +services, the industry experiences shortages of qualified +drilling rig personnel. During these periods, our ability to +attract and retain sufficient qualified personnel to market and +operate our drilling rigs is adversely affected, which +negatively impacts both our operations and profitability. +Operationally, it is more difficult to hire qualified personnel +which adversely affects our ability to mobilize inactive rigs in +response to the increased demand for our contract drilling +services. Additionally, wage rates for drilling personnel are +likely to increase, resulting in higher operating costs. +Continued +Growth Through Rig Acquisition is Not Assured. +We have increased our drilling rig fleet in the past through +mergers and acquisitions. The land drilling industry has +experienced significant consolidation, and there can be no +assurance that acquisition opportunities will be +11 +available in the future. Additionally, we are likely to continue +to face intense competition from other companies for available +acquisition opportunities. +There can be no assurance that we will: +• +have sufficient capital resources to complete additional +acquisitions, +• +successfully integrate acquired operations and assets, +• +effectively manage the growth and increased size, +• +successfully deploy idle or stacked rigs, +• +maintain the crews and market share to operate drilling rigs +acquired, or +• +successfully improve our financial condition, results of +operations, business or prospects in any material manner as a +result of any completed acquisition. +We may incur substantial indebtedness to finance future +acquisitions and also may issue equity securities or convertible +securities in connection with any such acquisitions. Debt +service requirements could represent a significant burden on our +results of operations and financial condition and the issuance +of additional equity would be dilutive to existing stockholders. +Also, continued growth could strain our management, operations, +employees and other resources. +The +Nature of our Business Operations Presents Inherent Risks of +Loss that, if not Insured or Indemnified Against, Could +Adversely Affect Our Operating Results. +Our operations are subject to many hazards inherent in the +contract drilling, pressure pumping, and drilling and completion +fluids businesses, which in turn could cause personal injury or +death, work stoppage, or serious damage to our equipment. Our +operations could also cause environmental and reservoir damages. +We maintain insurance coverage and have indemnification +agreements with many of our customers. However, there is no +assurance that such insurance or indemnification agreements +would adequately protect us against liability or losses from all +consequences of these hazards. Additionally, there can be no +assurance that insurance would be available to cover any or all +of these risks, or, even if available, that insurance premiums +or other costs would not rise significantly in the future, so as +to make such insurance prohibitive. +We have elected in some cases to accept a greater amount of risk +through increased deductibles on certain insurance policies. For +example, we maintain a $1.0 million per occurrence +deductible on our workers’ compensation, general liability +and equipment insurance coverages. +Violations +of Environmental Laws and Regulations Could Materially Adversely +Affect Our Operating Results. +The drilling of oil and natural gas wells is subject to various +Federal, state, foreign, and local laws, rules and regulations. +The cost of compliance with these laws and regulations could be +substantial. A failure to comply with these requirements could +expose us to substantial civil and criminal penalties. In +addition, Federal law imposes a variety of regulations on +“responsible parties” related to the prevention of oil +spills and liability for damages from such spills. As an owner +and operator of land-based drilling rigs, we may be deemed to be +a responsible party under Federal law. Our operations and +facilities are subject to numerous state and Federal +environmental laws, rules and regulations, including, without +limitation, laws concerning the containment and disposal of +hazardous substances, oil field waste and other waste materials, +the use of underground storage tanks and the use of underground +injection wells. +Some +of Our Contract Drilling Services are Provided Under Turnkey and +Footage Contracts, Which are Financially Risky. +A portion of our contract drilling is performed under turnkey +and footage contracts, which involve significant risks. Under +turnkey drilling contracts, we contract to drill a well to a +certain depth under specified conditions at a fixed price. Under +footage contracts, we contract to drill a well to a certain +depth under specified conditions at a +12 +fixed price per foot. The risk to us under these types of +drilling contracts are greater than on a well drilled on a +daywork basis. Unlike daywork contracts, we must bear the cost +of services until the target depth is reached. In addition, we +must assume most of the risk associated with the drilling +operations, generally assumed by the operator of the well on a +daywork contract, including blowouts, loss of hole from fire, +machinery breakdowns and abnormal drilling conditions. +Accordingly, if severe drilling problems are encountered in +drilling wells under such contracts, we could suffer substantial +losses. +Anti-takeover +Measures in Our Charter Documents and Under State Law Could +Discourage an Acquisition and Thereby Affect the Related +Purchase Price. +We are a Delaware corporation subject to the Delaware General +Corporation Law, including Section 203, an anti-takeover +law enacted in 1988. We have also enacted certain anti-takeover +measures, including a stockholders’ rights plan. In +addition, our Board of Directors has the authority to issue up +to one million shares of preferred stock and to determine the +price, rights (including voting rights), conversion ratios, +preferences and privileges of that stock without further vote or +action by the holders of the common stock. As a result of these +measures and others, potential acquirers might find it more +difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our +securities of certain opportunities to sell or otherwise dispose +of the securities at above-market prices pursuant to any such +transactions. +Item 1B. +Unresolved +Staff Comments. +None. +Item 2. +Properties +Our corporate headquarters are located in Snyder, Texas. We also +have a number of offices, yards and stockpoint facilities +located in our various operating areas. +Our corporate headquarters are located at 4510 Lamesa Highway, +Snyder, Texas, and our telephone number at that address is +(325) 574-6300. +There are a number of improvements at our headquarters, +including: +• +office buildings with approximately 37,000 square feet of +office space and storage, +• +a shop facility with approximately 7,000 square feet used +for drilling equipment repairs and metal fabrication, +• +a truck shop facility with approximately 10,000 square feet +used to maintain, overhaul and repair our truck fleet, +• +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 +• +a welding shop with approximately 10,000 square feet. +We have regional administrative offices, yards and stockpoint +facilities in many of the areas in which we operate. The +facilities are primarily used to support +day-to-day +operations, including the repair and maintenance of equipment as +well as the storage of equipment, inventory and supplies and to +facilitate administrative responsibilities and sales. +Contract Drilling Operations — Our drilling +services are supported by several administrative offices and +yard facilities located throughout our areas of operations +including: +• +Texas, +• +New Mexico, +• +Oklahoma, +• +Colorado, +13 +• +Utah, +• +Wyoming, and +• +Western Canada. +Pressure Pumping — Our pressure pumping +services are supported by several offices and yard facilities +located throughout our areas of operations including: +• +Pennsylvania, +• +Ohio, +• +West Virginia, +• +Kentucky, +• +Tennessee, +• +Wyoming, +• +Colorado, and +• +New York. +Drilling and Completion Fluids — Our drilling +and completion fluids services are supported by several +administrative offices and stockpoint facilities located +throughout our areas of operations including: +• +Texas, +• +Louisiana, +• +New Mexico, and +• +Oklahoma. +Oil and Natural Gas — Our oil and natural gas +operations are supported by administrative and field offices in +Texas. +We own our headquarters in Snyder, Texas, as well as several of +our other facilities. We also lease a number of facilities and +we do not believe that any one of the leased facilities is +individually material to our operations. We believe that our +existing facilities are suitable and adequate to meet our needs. +Item 3. +Legal +Proceedings. +In December 2005, two purported derivative actions were filed in +Texas state court in Scurry County, Texas and in May 2006, a +derivative action was filed in federal court in Lubbock, Texas, +in each case against our directors, alleging that the directors +breached their fiduciary duties to us as a result of alleged +failure to timely discover the embezzlement of approximately +$77.5 million by our former CFO, Jonathan D. Nelson. 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 were +stayed pending completion of the work of the special litigation +committee. The lawsuits sought recovery on behalf of and for us +and did not seek recovery from us. In November 2006, the parties +to all three of the derivative actions reached an agreement to +settle the actions. After a preliminary hearing and notice to +our stockholders, the state court held a hearing, approved the +settlement, which requires the implementation of certain +corporate governance measures, and signed a final judgment on +December 29, 2006. As contemplated by the settlement +agreement, the federal court entered a final judgment on +January 10, 2007. Pursuant to the terms of the settlement, +we will pay a net amount of $230,000 to the attorneys for the +plaintiffs in the suits. +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 effect on our financial +condition. +Item 4. +Submission +of Matters to a Vote of Security Holders. +None. +14 +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 $0.01 per share, is publicly +traded on the Nasdaq National Market and is quoted under the +symbol “PTEN.” Our common stock is included in the +S&P MidCap 400 Index and several other market indexes. The +following table provides high and low sales prices of our common +stock for the periods indicated: +High +Low +2006: +First quarter +$ +38.49 +$ +25.61 +Second quarter +35.65 +25.24 +Third quarter +29.11 +21.84 +Fourth quarter +28.21 +20.81 +2005: +First quarter +$ +26.66 +$ +17.15 +Second quarter +29.33 +22.38 +Third quarter +36.79 +27.79 +Fourth quarter +36.73 +28.45 +(b) +Holders +As of February 21, 2007, there were approximately 2,200 +holders of record and approximately 79,500 beneficial holders of +our common stock. +(c) +Dividends +and Buyback Program +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. At June 30, 2004, an +adjustment was made to reclassify an amount from retained +earnings to common stock to account for the par value of the +common stock issued as a stock dividend. This adjustment had no +overall effect on equity. All historical share and per-share +information prior to June 30, 2004 has been restated to +reflect the impact of the +two-for-one +stock split. +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, +September 1, 2004 and December 1, 2004. Total +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. On March 2, 2006, our +Board of Directors approved a cash dividend on our common stock +in the amount of $0.04 per share which was paid on +March 30, 2006. On April 26, 2006, our Board of +Directors approved an increase in our quarterly cash dividend +from $0.04 to $0.08 on each outstanding share of our common +stock. Cash dividends of $0.08 per share were paid on +June 30, 2006, September 29, 2006 and +December 29, 2006. Total cash dividends in 2006 were +approximately $45.8 million. The amount and timing of all +future dividend payments is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +15 +The table below sets forth the information with respect to +purchases of our common stock made by us during the quarter +ended December 31, 2006. +Total number +Approximate +of shares +dollar value +(or units) +of shares +purchased as +that may yet +part of +be purchased +Total number +Average price +publicly announced +under the +of shares +paid per +plans or +plans or +Period covered +purchased(1) +share +programs(2) +programs(2) +October +1–31, +2006 +1,025,000 +$ +22.20 +1,025,000 +$ +60,572,000 +November +1–30, +2006 +2,378,542 +$ +25.47 +2,378,542 +$ +— +December +1–31, +2006 +— +$ +— +— +$ +— +Total +3,403,542 +$ +24.48 +3,403,542 +$ +— +(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. During 2004, we purchased +100,000 shares of our common stock in the open market for +approximately $1.5 million. During 2005, we purchased +355,000 shares of our common stock in the open market for +approximately $12.2 million. On March 27, 2006, our +Board of Directors increased the previously authorized stock +buyback program to allow for future purchases of up to +$200 million of our outstanding common stock. During the +second quarter of 2006, we completed the authorized buyback with +the purchase of 6,704,800 shares of our common stock at a +cost of approximately $200 million. On August 2, 2006, +our Board of Directors again increased the previously authorized +stock buyback program to allow for future purchases of up to +$250 million of our outstanding common stock. During the +remainder of 2006, we purchased an additional +9,940,542 shares of our common stock at a cost of +approximately $250 million. Shares purchased under the +stock buyback program during 2006 totaled $450 million and +have been accounted for as treasury stock. +(d) +Securities +Authorized for Issuance Under Equity Compensation +Plans +Equity compensation to our employees, officers and directors as +of December 31, 2006 follows: +Equity Compensation Plan Information +Number of +Securities Remaining +Number of +Available for +Securities to +Future Issuance +be Issued +Weighted- Average +under Equity +upon Exercise +Exercise Price +Compensation Plans +of Outstanding +of Outstanding +(Excluding Securities +Options, Warrants +Options, Warrants +Reflected in +Plan Category +and Rights +and Rights +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved +by security holders(1) +5,812,537 +$ +17.02 +4,140,197 +Equity compensation plans not +approved by security holders(2) +762,559 +$ +9.84 +— +Total +6,575,096 +$ +16.18 +4,140,197 +(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, officers +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 +16 +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. +(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 officers 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. +17 +Item 6. +Selected +Financial Data. +Our selected consolidated financial data as of December 31, +2006, 2005, 2004, 2003 and 2002, and for each of the five years +then ended should be read in conjunction with +“Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and the Consolidated +Financial Statements and related Notes thereto, included as +Items 7 and 8, respectively, of this Report. Certain +reclassifications have been made to the historical financial +data to conform with the 2006 presentation. +Years Ended December 31, +2006 +2005 +2004 +2003 +2002 +(In thousands, except per share amounts) +Income Statement +Data: +Operating revenues: +Contract drilling +$ +2,169,370 +$ +1,485,684 +$ +809,691 +$ +639,694 +$ +410,295 +Pressure pumping +145,671 +93,144 +66,654 +46,083 +32,996 +Drilling and completion fluids +192,358 +122,011 +90,557 +69,230 +69,943 +Oil and natural gas +39,187 +39,616 +33,867 +21,163 +14,723 +Total +2,546,586 +1,740,455 +1,000,769 +776,170 +527,957 +Operating costs and expenses: +Contract drilling +1,002,001 +776,313 +556,869 +475,224 +318,201 +Pressure pumping +77,755 +54,956 +37,561 +26,184 +19,802 +Drilling and completion fluids +150,372 +98,530 +76,503 +61,424 +60,762 +Oil and natural gas +13,374 +9,566 +7,978 +4,808 +3,956 +Depreciation, depletion, +amortization and impairment +196,370 +156,393 +122,800 +100,834 +92,778 +Selling, general and administrative +55,065 +39,110 +31,983 +27,685 +26,116 +Embezzlement costs, net of +recoveries +3,081 +20,043 +19,122 +17,849 +8,574 +Other operating expenses +9,404 +4,248 +(514 +) +(4,120 +) +4,660 +Total +1,507,422 +1,159,159 +852,302 +709,888 +534,849 +Operating income (loss) +1,039,164 +581,296 +148,467 +66,282 +(6,892 +) +Other income +4,670 +3,463 +680 +2,694 +803 +Income (loss) before income taxes +and cumulative effect of change in accounting principle +1,043,834 +584,759 +149,147 +68,976 +(6,089 +) +Income tax expense (benefit) +371,267 +212,019 +54,801 +25,320 +(1,949 +) +Income (loss) before cumulative +effect of change in accounting principle +672,567 +372,740 +94,346 +43,656 +(4,140 +) +Cumulative effect of change in +accounting principle, net of related income tax expense of $398 +in 2006 and benefit of $287 in 2003 +687 +— +— +(469 +) +— +Net income (loss) +$ +673,254 +$ +372,740 +$ +94,346 +$ +43,187 +$ +(4,140 +) +Net income (loss) per common share: +Basic: +Income (loss) before cumulative +effect of change in accounting principle +$ +4.07 +$ +2.19 +$ +0.57 +$ +0.27 +$ +(0.03 +) +Cumulative effect of change in +accounting principle +$ +— +$ +— +$ +— +$ +— +$ +— +Net income (loss) +$ +4.08 +$ +2.19 +$ +0.57 +$ +0.27 +$ +(0.03 +) +18 +Years Ended December 31, +2006 +2005 +2004 +2003 +2002 +(In thousands, except per share amounts) +Diluted: +Income (loss) before cumulative +effect of change in accounting principle +$ +4.02 +$ +2.15 +$ +0.56 +$ +0.27 +$ +(0.03 +) +Cumulative effect of change in +accounting principle +$ +— +$ +— +$ +— +$ +— +$ +— +Net income (loss) +$ +4.02 +$ +2.15 +$ +0.56 +$ +0.26 +$ +(0.03 +) +Cash dividends per common share +$ +0.28 +$ +0.16 +$ +0.06 +$ +— +$ +— +Weighted average number of common +shares outstanding: +Basic +165,159 +170,426 +166,258 +161,272 +157,410 +Diluted +167,413 +173,767 +169,211 +164,572 +157,410 +Balance Sheet Data: +Total assets +$ +2,192,503 +$ +1,795,781 +$ +1,256,785 +$ +1,039,521 +$ +919,374 +Borrowings under line of credit +120,000 +— +— +— +— +Stockholders’ equity +1,562,466 +1,367,011 +961,501 +789,814 +724,248 +Working capital +335,052 +382,448 +235,480 +198,399 +166,885 +19 +Item 7. +Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +This Item 7 contains forward-looking statements, which are +made pursuant to the “Safe Harbor” provisions of the +Private Securities Litigation Reform Act of 1995. +Management Overview — We are a leading provider +of contract services to the North American oil and natural gas +industry. Our services primarily involve the drilling, on a +contract basis, of land-based oil and natural gas wells and to a +lesser extent, we provide pressure pumping services and drilling +and completion fluid services. In addition to the aforementioned +contract services, we also engage in the development, +exploration, acquisition and production of oil and natural gas. +For the three years ended December 31, 2006, our operating +revenues consisted of the following (dollars in thousands): +2006 +2005 +2004 +Contract drilling +$ +2,169,370 +84 +% +$ +1,485,684 +86 +% +$ +809,691 +81 +% +Pressure pumping +145,671 +6 +93,144 +5 +66,654 +7 +Drilling and completion fluids +192,358 +8 +122,011 +7 +90,557 +9 +Oil and natural gas +39,187 +2 +39,616 +2 +33,867 +3 +$ +2,546,586 +100 +% +$ +1,740,455 +100 +% +$ +1,000,769 +100 +% +We provide our contract services to oil and natural gas +operators in many of the oil and natural gas producing regions +of North America. Our contract drilling operations are focused +in various regions of Texas, New Mexico, Oklahoma, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, South Dakota and Western Canada, while our pressure +pumping services are focused primarily in the Appalachian Basin. +Our drilling and completion fluids services are provided to +operators offshore in the Gulf of Mexico and on land in Texas, +Southeastern New Mexico, Oklahoma and the Gulf Coast region of +Louisiana. Our oil and natural gas operations are primarily +focused in West and South Texas, Southeastern New Mexico, Utah +and Mississippi. +The profitability of our business is most readily assessed by +two primary indicators in our contract drilling segment: our +average number of rigs operating and our average revenue per +operating day. During 2006, our average number of rigs operating +increased to 296 from 276 in 2005 and our average revenue per +operating day increased to $20,050 from $14,770 in 2005. +Primarily due to these improvements, we experienced an increase +of approximately $301 million, or 81%, in consolidated net +income in 2006. +Our revenues, profitability and cash flows are highly dependent +upon the market prices of oil and natural gas. During periods of +improved commodity prices, the capital spending budgets of oil +and natural gas operators tend to expand, which results in +increased demand for our contract services. Conversely, in +periods of time when these commodity prices deteriorate, the +demand for our contract services generally weakens and we +experience downward pressure on pricing for our services. +We believe that the liquidity shown on our balance sheet as of +December 31, 2006, which includes approximately +$335 million in working capital (including +$13.4 million in cash) and $195 million available +under a $375 million line of credit ($120 million in +borrowings are outstanding at December 31, 2006 and +availability of $60 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, pay cash dividends and survive +downturns in our industry. +Commitments and Contingencies — We maintain +letters of credit in the aggregate amount of approximately +$60 million for the benefit of various insurance companies +as collateral for retrospective premiums and retained losses +which could become payable under the terms of the underlying +insurance contracts. These letters of credit expire at various +times during each calendar year. No amounts have been drawn +under the letters of credit. +As of December 31, 2006, we have remaining non-cancelable +commitments to purchase approximately $297 million of +equipment to be received throughout 2007. +In November 2005, we discovered that our former Chief Financial +Officer, Jonathan D. Nelson (“Nelson”), had +fraudulently diverted approximately $77.5 million of our +funds for his own benefit. As a result, the Audit Committee of +the Board of Directors commenced an investigation into +Nelson’s activities and retained independent counsel and +independent forensic accountants to assist with the +investigation. Nelson has been sentenced and is +20 +serving a term of imprisonment arising out of his embezzlement. +A receiver has been appointed to take control of and liquidate +the assets of Nelson in connection with his embezzlement of our +funds. The receiver is in the process of seeking court approval +for a plan of distribution of the assets recovered by the +receiver and the proceeds thereof, which total approximately +$40 million. While we believe we have a claim for at least +the full amount of funds embezzled from us, other creditors have +asserted or may assert claims with respect to the assets held by +the receiver. +In December 2005, two purported derivative actions were filed in +Texas state court in Scurry County, Texas and in May 2006, a +derivative action was filed in federal court in Lubbock, Texas, +in each case against our directors, alleging that the directors +breached their fiduciary duties to us as a result of alleged +failure to timely discover the embezzlement of approximately +$77.5 million by our former CFO, Jonathan D. Nelson. 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 were +stayed pending completion of the work of the special litigation +committee. The lawsuits sought recovery on behalf of and for us +and did not seek recovery from us. In November 2006, the parties +to all three of the derivative actions reached an agreement to +settle the actions. After a preliminary hearing and notice to +our stockholders, the state court held a hearing, approved the +settlement, which requires the implementation of certain +corporate governance measures, and signed a final judgment on +December 29, 2006. As contemplated by the settlement +agreement, the federal court entered a final judgment on +January 10, 2007. Pursuant to the terms of the settlement, +we will pay a net amount of $230,000 to the attorneys for the +plaintiffs in the suits. +Trading and investing — We have not engaged in +trading activities that include high-risk securities, such as +derivatives and non-exchange traded contracts. We invest cash +primarily in highly liquid, short-term investments such as +overnight deposits, money markets and highly rated municipal and +commercial bonds. +Description of business — We conduct our +contract drilling operations in Texas, New Mexico, Oklahoma, +Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, +Montana, North Dakota, South Dakota and Western Canada. As +of December 31, 2006, we had 336 currently marketable +land-based drilling rigs. We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. These services consist primarily of well stimulation and +cementing for completion of new wells and remedial work on +existing wells. We provide drilling fluids, completion fluids +and related services to oil and natural gas operators offshore +in the Gulf of Mexico and on land in Texas, Southeastern New +Mexico, Oklahoma and the Gulf Coast region of Louisiana. +Drilling and completion fluids are used by oil and natural gas +operators during the drilling process to control pressure when +drilling oil and natural gas wells. We are also engaged in the +development, exploration, acquisition and production of oil and +natural gas. Our oil and natural gas operations are focused +primarily in producing regions in West and South Texas, +Southeastern New Mexico, Utah and Mississippi. +Critical +Accounting Policies +In addition to established accounting policies, our consolidated +financial statements are impacted by certain estimates and +assumptions made by management. The following is a discussion of +our critical accounting policies pertaining to property and +equipment, oil and natural gas properties, goodwill, revenue +recognition and the use of estimates. +Property and equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our assets +for impairment when events or changes in circumstances indicate +that the carrying values of certain assets either exceed their +respective fair values or may not be recovered over their +estimated remaining useful lives. The cyclical nature of our +industry has resulted in fluctuations in rig utilization over +periods of time. Management believes that the contract drilling +industry will continue to be cyclical and rig utilization will +fluctuate. Based on management’s expectations of future +trends, we estimate future cash flows over the life of the +respective assets in our assessment of impairment. These +estimates of cash flows are based on historical cyclical trends +in the industry as well as management’s expectations +regarding the continuation of these trends in the future. +Provisions for asset impairment are charged to income when +estimated future cash flows, on an undiscounted basis, are less +than the asset’s net book value. Impairment charges are +recorded based on discounted cash flows. There were no +impairment charges to property and equipment during the years +2006, 2005 or 2004. +21 +Oil and natural gas properties — Oil and +natural gas properties are accounted for using the successful +efforts method of accounting. Under the successful efforts +method of accounting, exploration costs which result in the +discovery of oil and natural gas reserves and all development +costs are capitalized to the appropriate well. Exploration costs +which do not result in discovering oil and natural gas reserves +are charged to expense when such 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 whether sufficient progress is being made in +assessing the reserves and the economic operating viability of +the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project 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 field. We review our proved oil +and natural gas properties for impairment when an event occurs +such as downward revisions in reserve estimates or decreases in +oil and natural gas prices. Proved properties are grouped by +field and undiscounted cash flow estimates are prepared +internally and reviewed by an independent petroleum engineer. If +the net book value of a field exceeds its undiscounted cash flow +estimate, impairment expense is measured and recognized as the +difference between its net book value and discounted cash flow. +Unproved oil and natural gas properties are reviewed quarterly +to determine impairment. Our intent to drill, lease expiration +and abandonment of area are considered. Assessment of impairment +is made on a +lease-by-lease +basis. If an unproved property is determined to be impaired, +then costs related to that property are expensed. Impairment +expense of approximately $5.0 million, $4.4 million +and $3.2 million for the years ended December 31, +2006, 2005 and 2004, respectively, is included in depreciation, +depletion and impairment in the accompanying financial +statements. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. As such, +we assess impairment of our goodwill annually or on an interim +basis if events or circumstances indicate that the fair value of +the asset has decreased below its carrying value. +Revenue recognition — 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. We recognize reimbursements received from third +parties for +out-of-pocket +expenses incurred as revenues and account for +out-of-pocket +expenses as direct costs. +Use of estimates — The preparation of financial +statements in conformity with accounting principles generally +accepted in the United States of America requires management to +make certain estimates and assumptions that affect the reported +amounts of assets and liabilities and disclosures of contingent +assets and liabilities at the date of the financial statements +and the reported amounts of revenues and expenses during the +reporting period. Actual results could differ from such +estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +total expenses to be incurred on footage and turnkey drilling +contracts, +• +depreciation and depletion, +• +asset impairment, +• +reserves for self-insured levels of insurance coverages, and +• +fair values of assets and liabilities assumed in acquisitions. +22 +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 affiliated persons have participated, either +individually or through entities they control. These +participations have typically been through working interests in +prospects or properties we originated or acquired. At +December 31, 2006, affiliated persons were working interest +owners in 281 of 330 total wells we operated. We make sales of +working interests to reduce our economic risk in the properties. +Generally, it is more efficient for us to sell the working +interests to these affiliated persons than to market them to +unrelated third parties. Sales of working interests to +affiliated parties were made at cost, comprised of our costs of +acquiring and preparing the working interests for sale plus a +promote fee in some cases. These costs were paid by the working +interest owners on a pro rata basis based upon their working +interest ownership percentage. The price at which working +interests were sold to affiliated persons was the same price as +that at which working interests were sold to unaffiliated +persons, except that in some cases the affiliated persons also +paid a promote fee. +Production revenues and joint interest costs of each of the +affiliated persons during 2006 for all wells operated by us in +which the affiliated persons have working interests are +presented in the table below. These amounts do not necessarily +represent their profits or losses from these interests because +the joint interest costs do not include the parties’ +related drilling and leasehold acquisition costs incurred prior +to January 1, 2006. These activities resulted in a payable +to the affiliated persons of approximately $1.5 million and +$1.5 million and a receivable from the affiliated persons +of approximately $1.6 million and $1.2 million at +December 31, 2006 and 2005, respectively. +Year Ended +December 31, 2006 +Joint Interest +Name +Production Revenues(1) +Costs(2) +Cloyce A. Talbott +$ +301,445 +$ +95,074 +Jana Talbott, Executrix to the +Estate of Steve Talbott(3) +20,621 +5,513 +Stan Talbott(3) +8,597 +4,043 +John Evan Talbott Trust(3) +3,825 +875 +Lisa Beck and Stacy Talbott(3) +1,311,651 +893,903 +SSI Oil & Gas, Inc.(4) +225,360 +181,970 +IDC Enterprises, Ltd.(5) +13,741,205 +12,829,963 +Subtotal +15,612,704 +14,011,341 +A. Glenn Patterson(6) +125,390 +40,104 +Robert Patterson(6) +9,071 +4,904 +Thomas M. Patterson(6) +9,071 +4,904 +Subtotal +143,532 +49,912 +Total +$ +15,756,236 +$ +14,061,253 +(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) +Stan Talbott, Lisa Beck and Stacy Talbott are +Mr. Talbott’s adult children. Steve Talbott is the +deceased son of Mr. Talbott. John Evan Talbott is +Mr. Talbott’s grandson. +(4) +SSI Oil & Gas, Inc. is beneficially owned 50% by Cloyce +A. Talbott and directly owned 50% by A. Glenn Patterson. +(5) +IDC Enterprises, Ltd. is 50% owned by Cloyce A. Talbott and 50% +owned by A. Glenn Patterson. +(6) +Through April 2006, A. Glenn Patterson was our President and +Chief Operating Officer. Robert and Thomas M. Patterson are A. +Glenn Patterson’s adult children. +23 +Liquidity +and Capital Resources +As of December 31, 2006, we had working capital of +$335 million including cash and cash equivalents of +$13 million. For 2006, our sources of cash flow included: +• +$837 million from operating activities, +• +$120 million in net proceeds from borrowings under our line +of credit, +• +$11 million in proceeds from the disposal of property and +equipment, and +• +$3 million from the exercise of stock options and related +tax benefits. +We used $450 million to purchase shares of our common stock +in the open market, $46 million to pay dividends on our +common stock, and $598 million: +• +to make capital expenditures for the betterment and +refurbishment of our drilling rigs, +• +to acquire and procure drilling equipment and facilities to +support our drilling operations, +• +to fund capital expenditures for our pressure pumping and +drilling and completion fluids divisions, and +• +to fund leasehold acquisition and exploration and development of +oil and natural gas properties. +On August 2, 2006, we entered into an agreement to amend +our $200 million unsecured revolving line of credit +(“LOC”). In connection with this amendment, the +borrowing capacity under this LOC was increased to +$375 million. No significant changes were made to the terms +of the LOC, including the interest to be paid on outstanding +balances and financial covenants. As of December 31, 2006, +we had borrowed $120 million under the LOC and +$60 million in letters of credit were outstanding. As a +result, we had available borrowing capacity of $195 million +at December 31, 2006. +On March 2, 2006, our Board of Directors approved a cash +dividend on our common stock in the amount of $0.04 per +share. The dividend of approximately $6.9 million was paid +on March 30, 2006. On April 26, 2006, our Board of +Directors approved an increase in our quarterly cash dividend +from $0.04 to $0.08 on each outstanding share of our common +stock. This dividend of approximately $13.4 million was +paid on June 30, 2006 to holders of record on June 15, +2006. On August 2, 2006, our Board of Directors approved a +quarterly cash dividend of $0.08 on each outstanding share of +our common stock. This dividend of approximately +$13.0 million was paid on September 29, 2006 to +holders of record as of September 14, 2006. On +October 31, 2006, our Board of Directors approved a +quarterly cash dividend of $0.08 on each outstanding share of +our common stock. This dividend of approximately +$12.5 million was paid on December 29, 2006 to holders +of record as of December 14, 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, financial condition, terms of our credit +facilities and other factors. +On March 27, 2006, our Board of Directors increased our +previously authorized stock buyback program to allow for future +purchases of up to $200 million of our outstanding common +stock. During the second quarter of 2006, we completed the +authorized buyback with the purchase of 6,704,800 shares of +our common stock at a cost of approximately $200 million. +On August 2, 2006, our Board of Directors again increased +the previously authorized stock buyback program to allow for +future purchases of up to $250 million of our outstanding +common stock. During the remainder of 2006, we purchased an +additional 9,940,542 shares of our common stock at a cost +of approximately $250 million. Shares purchased under the +stock buyback program have been accounted for as treasury stock. +We believe that the current level of cash and short-term +investments, together with cash generated from operations, +should be sufficient to meet our capital needs. From time to +time, acquisition opportunities are evaluated. The timing, size +or success of any acquisition and the associated capital +commitments are unpredictable. Should opportunities for growth +requiring capital arise, we believe we would be able to satisfy +these needs through a combination of working capital, cash +generated from operations, our existing credit facility and +additional debt or equity financing. However, there can be no +assurance that such capital would be available. +24 +Contractual +Obligations +The following table presents information with respect to our +contractual obligations as of December 31, 2006 (dollars in +thousands): +Payments Due by Period +Less Than +More Than +Total +1 Year +1-3 Years +3-5 Years +5 Years +Borrowings under line of credit(1) +$ +120,000 +$ +— +$ +120,000 +$ +— +$ +— +Commitments to purchase +equipment(2) +296,577 +296,577 +— +— +— +$ +416,577 +$ +296,577 +$ +120,000 +$ +— +$ +— +(1) +Our line of credit is a revolving line of credit that matures on +December 16, 2009. So long as we are in compliance with our +obligations under the credit agreement, no principal repayments +are required until maturity. +(2) +Represents non-cancelable commitments to purchase equipment to +be delivered throughout 2007. +Off-Balance +Sheet Arrangements +We had no off-balance sheet arrangements at December 31, +2006. +Results +of Operations +Comparison +of the years ended December 31, 2006 and 2005 +A summary of operations by business segment for the years ended +December 31, 2006 and 2005 follows: +Year Ended December 31, +Contract Drilling +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +2,169,370 +$ +1,485,684 +46.0 +% +Direct operating costs +$ +1,002,001 +$ +776,313 +29.1 +% +Selling, general and administrative +$ +7,313 +$ +5,069 +44.3 +% +Depreciation +$ +168,607 +$ +131,740 +28.0 +% +Operating income +$ +991,449 +$ +572,562 +73.2 +% +Operating days +108,192 +100,591 +7.6 +% +Average revenue per operating day +$ +20.05 +$ +14.77 +35.7 +% +Average direct operating costs per +operating day +$ +9.26 +$ +7.72 +19.9 +% +Number of rigs operated +331 +307 +7.8 +% +Average rigs operating +296 +276 +7.2 +% +Capital expenditures +$ +531,087 +$ +329,073 +61.4 +% +Our average number of rigs operating increased to 296 in 2006 +from 276 in 2005. The average market price of natural gas and +our average rigs operating for each of the fiscal quarters and +full years in 2006 and 2005 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2006: +Average natural gas price(1) +$ +7.93 +$ +6.74 +$ +6.26 +$ +6.87 +$ +6.94 +Average rigs operating +300 +295 +301 +290 +296 +2005: +Average natural gas price(1) +$ +6.62 +$ +7.14 +$ +9.82 +$ +12.64 +$ +8.98 +Average rigs operating +263 +265 +283 +292 +276 +(1) +The average natural gas price above represents the Henry Hub +Spot price as reported by the United States Energy Information +Administration. +25 +Revenues and direct operating costs increased as a result of the +increased number of operating days, as well as an increase in +the average revenue and average direct operating costs per +operating day. Operating days and average rigs operating +increased as a result of increased demand for our contract +drilling services and the increase in the number of marketable +rigs in our fleet due to our rig activation program. Average +revenue per operating day increased as a result of increased +demand and pricing for our drilling services. Average direct +operating costs per operating day increased primarily as a +result of increased compensation costs and an increase in the +cost of maintenance for our rigs. Significant capital +expenditures have been incurred to activate additional drilling +rigs, to modify and upgrade our drilling rigs and to acquire +additional related equipment such as drill pipe, drill collars, +engines, fluid circulating systems, rig hoisting systems and +safety enhancement equipment. The increase in depreciation +expense was a result of the capital expenditures discussed above. +Year Ended December 31, +Pressure Pumping +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +145,671 +$ +93,144 +56.4 +% +Direct operating costs +$ +77,755 +$ +54,956 +41.5 +% +Selling, general and administrative +$ +13,185 +$ +9,430 +39.8 +% +Depreciation +$ +9,896 +$ +7,094 +39.5 +% +Operating income +$ +44,835 +$ +21,664 +107.0 +% +Total jobs +11,650 +9,615 +21.2 +% +Average revenue per job +$ +12.50 +$ +9.69 +29.0 +% +Average direct operating costs per +job +$ +6.67 +$ +5.72 +16.6 +% +Capital expenditures +$ +41,262 +$ +25,508 +61.8 +% +Revenues and direct operating costs increased as a result of the +increased number of jobs, as well as an increase in the average +revenue and average direct operating cost per job. The increase +in jobs was attributable to increased demand for our services +and increased operating capacity which has been added. Increased +average revenue per job was due to increased pricing for our +services and an increase in the number of larger jobs. Average +direct operating costs per job increased as a result of +increases in compensation and the cost of materials used in our +operations as well as an increase in the number of larger jobs. +Selling, general and administrative expense increased as a +result of additional expenses to support the expanded operations +of the pressure pumping segment. Significant capital +expenditures have been incurred to add capacity and modify and +upgrade existing equipment. The increase in depreciation expense +was a result of the capital expenditures discussed above. +Year Ended December 31, +Drilling and Completion Fluids +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +192,358 +$ +122,011 +57.7 +% +Direct operating costs +$ +150,372 +$ +98,530 +52.6 +% +Selling, general and administrative +$ +10,521 +$ +8,912 +18.1 +% +Depreciation +$ +2,706 +$ +2,368 +14.3 +% +Operating income +$ +28,759 +$ +12,201 +135.7 +% +Total jobs +2,042 +1,980 +3.1 +% +Average revenue per job +$ +94.20 +$ +61.62 +52.9 +% +Average direct operating costs per +job +$ +73.64 +$ +49.76 +48.0 +% +Capital expenditures +$ +4,222 +$ +3,042 +38.8 +% +Revenues and direct operating costs increased primarily as a +result of increases 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 large jobs +in the Gulf of Mexico. +26 +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2006 +2005 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +39,187 +$ +39,616 +(1.1 +)% +Direct operating costs +$ +13,374 +$ +9,566 +39.8 +% +Selling, general and administrative +$ +2,785 +$ +2,189 +27.2 +% +Depreciation, depletion and +impairment +$ +14,368 +$ +14,456 +(0.6 +)% +Operating income +$ +8,660 +$ +13,405 +(35.4 +)% +Capital expenditures +$ +21,198 +$ +17,163 +23.5 +% +Average net daily oil production +(Bbls) +983 +860 +14.3 +% +Average net daily gas production +(Mcf) +5,143 +7,016 +(26.7 +)% +Average oil sales price (per Bbl) +$ +63.83 +$ +54.30 +17.6 +% +Average gas sales price (per Mcf) +$ +6.82 +$ +7.64 +(10.7 +)% +Direct operating costs increased primarily due to +$4.2 million in costs associated with the abandonment of +exploratory wells. Depreciation, depletion and impairment +expense includes $5.0 million and $4.4 million +incurred during 2006 and 2005, respectively, to reflect the +impairment of certain oil and natural gas properties. Average +net daily oil production increased due to the completion of new +wells in 2006. Average net daily natural gas production +decreased as a result of production declines and the sale of +certain natural gas properties. +Year Ended December 31, +Corporate and Other +2006 +2005 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +21,261 +$ +13,510 +57.4 +% +Depreciation +$ +793 +$ +735 +7.9 +% +Other operating expenses +$ +9,404 +$ +4,248 +121.4 +% +Embezzlement costs, net of +recoveries +$ +3,081 +$ +20,043 +(84.6 +)% +Interest income +$ +5,925 +$ +3,551 +66.9 +% +Interest expense +$ +1,602 +$ +516 +210.5 +% +Other income +$ +347 +$ +428 +(18.9 +)% +Capital expenditures +$ +150 +$ +5,308 +(97.2 +)% +Selling, general and administrative expense increased primarily +as a result of an increase of $7.8 million in stock-based +compensation expense which was impacted by the adoption of a new +accounting standard in 2006 requiring the expensing of stock +options. Other operating expenses include bad debt expense of +$5.4 million and $1.2 million in 2006 and 2005, +respectively. Embezzlement costs, net of recoveries in 2005 +includes payments made to or for the benefit of Jonathan D. +Nelson, our former CFO, for assets and services that were not +received by the Company and in 2006 includes continuing +professional and other costs related to the embezzlement, net of +insurance proceeds of $2.0 million received in connection +with the loss. Interest expense in 2006 increased due to +borrowings under our line of credit during 2006. +27 +Comparison +of the years ended December 31, 2005 and 2004 +A summary of operations by business segment for the years ended +December 31, 2005 and 2004 follows: +Year Ended December 31, +Contract Drilling +2005 +2004 +% Change +(Dollars in thousands) +Revenues +$ +1,485,684 +$ +809,691 +83.5 +% +Direct operating costs +$ +776,313 +$ +556,869 +39.4 +% +Selling, general and administrative +$ +5,069 +$ +4,417 +14.8 +% +Depreciation +$ +131,740 +$ +101,779 +29.4 +% +Operating income +$ +572,562 +$ +146,626 +290.5 +% +Operating days +100,591 +77,355 +30.0 +% +Average revenue per operating day +$ +14.77 +$ +10.47 +41.1 +% +Average direct operating costs per +operating day +$ +7.72 +$ +7.20 +7.2 +% +Number of rigs operated +307 +259 +18.5 +% +Average rigs operating +276 +211 +30.8 +% +Capital expenditures +$ +329,073 +$ +140,945 +133.5 +% +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 fiscal quarters and +full years in 2005 and 2004 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2005: +Average natural gas price(1) +$ +6.62 +$ +7.14 +$ +9.82 +$ +12.64 +$ +8.98 +Average rigs operating +263 +265 +283 +292 +276 +2004: +Average natural gas price(1) +$ +5.64 +$ +6.13 +$ +5.62 +$ +6.42 +$ +5.95 +Average rigs operating +197 +203 +216 +229 +211 +(1) +The average natural gas price above represents the Henry Hub +Spot price as reported by the United States Energy Information +Administration. +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 and the increase in the number of marketable +rigs in our fleet due to the acquisition of land drilling assets +from Key Energy Services, Inc. in January 2005 and our rig +activation program. Average revenue per operating day increased +as a result of increased demand and pricing for our drilling +services. Significant capital expenditures were incurred during +2005 to activate additional drilling rigs to meet increased +demand, to modify and upgrade our drilling rigs and to acquire +additional related equipment such as drill pipe, drill collars, +engines, fluid circulating systems, rig hoisting systems and +safety +28 +enhancement equipment. The increase in depreciation expense was +a result of the capital expenditures discussed above. +Year Ended December 31, +Pressure Pumping +2005 +2004 +% Change +(Dollars in thousands) +Revenues +$ +93,144 +$ +66,654 +39.7 +% +Direct operating costs +$ +54,956 +$ +37,561 +46.3 +% +Selling, general and administrative +$ +9,430 +$ +7,234 +30.4 +% +Depreciation +$ +7,094 +$ +5,112 +38.8 +% +Operating income +$ +21,664 +$ +16,747 +29.4 +% +Total jobs +9,615 +7,444 +29.2 +% +Average revenue per job +$ +9.69 +$ +8.95 +8.3 +% +Average direct operating costs per +job +$ +5.72 +$ +5.05 +13.3 +% +Capital expenditures +$ +25,508 +$ +17,705 +44.1 +% +Revenues and direct operating costs increased as a result of the +increased number of jobs, as well as an increase in the average +revenue and average direct operating costs per job. The increase +in jobs in 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 modifications and +upgrades to existing equipment and facilities. +Year Ended December 31, +Drilling and Completion Fluids +2005 +2004 +% Change +(Dollars in thousands) +Revenues +$ +122,011 +$ +90,557 +34.7 +% +Direct operating costs +$ +98,530 +$ +76,503 +28.8 +% +Selling, general and administrative +$ +8,912 +$ +7,696 +15.8 +% +Depreciation +$ +2,368 +$ +2,156 +9.8 +% +Operating income +$ +12,201 +$ +4,202 +190.4 +% +Total jobs +1,980 +2,205 +(10.2 +)% +Average revenue per job +$ +61.62 +$ +41.07 +50.0 +% +Average direct operating costs per +job +$ +49.76 +$ +34.70 +43.4 +% +Capital expenditures +$ +3,042 +$ +1,488 +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 +29 +increase in the size of our offshore jobs. Selling, general and +administrative expense increased primarily due to increased +incentive compensation resulting from higher profitability +levels. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2005 +2004 +% Change +(Dollars in thousands, except for commodity prices)} +Revenues +$ +39,616 +$ +33,867 +17.0 +% +Direct operating costs +$ +9,566 +$ +7,978 +19.9 +% +Selling, general and administrative +$ +2,189 +$ +1,816 +20.5 +% +Depreciation, depletion and +impairment +$ +14,456 +$ +13,309 +8.6 +% +Operating income +$ +13,405 +$ +10,764 +24.5 +% +Capital expenditures +$ +17,163 +$ +14,451 +18.8 +% +Average net daily oil production +(Bbls) +860 +1,071 +(19.7 +)% +Average net daily gas production +(Mcf) +7,016 +7,429 +(5.6 +)% +Average oil sales price (per Bbl) +$ +54.30 +$ +39.12 +38.8 +% +Average gas sales price (per Mcf) +$ +7.64 +$ +5.81 +31.5 +% +Revenues increased due to increased market prices for oil and +natural gas. Direct operating costs increased as a result of +higher oilfield 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 offset by an increase in production. +Depreciation, depletion and impairment expense includes +approximately $4.4 million and $3.2 million of +expenses incurred during 2005 and 2004, respectively, to impair +certain oil and gas properties. +Year Ended December 31, +Corporate and Other +2005 +2004 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +13,510 +$ +10,820 +24.9 +% +Depreciation +$ +735 +$ +444 +65.5 +% +Other operating expenses +$ +4,248 +$ +(514 +) +N/A +% +Embezzlement costs, net of +recoveries +$ +20,043 +$ +19,122 +4.8 +% +Interest income +$ +3,551 +$ +1,140 +211.5 +% +Interest expense +$ +516 +$ +695 +(25.8 +)% +Other income +$ +428 +$ +235 +82.1 +% +Capital expenditures +$ +5,308 +$ +— +N/A +% +Selling, general and administrative expenses increased primarily +as a result of payroll taxes attributable to the exercise of +employee stock options, increased professional fees and +additional compensation expense related to the issuance of +restricted shares to certain key employees in 2004 and 2005. +Embezzlement costs, net of recoveries includes fraudulent +payments made to or for the benefit 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 operating expenses in 2005 +includes a charge of $4.2 million to increase reserves +related to the financial failure of a workers’ compensation +insurance carrier used previously by the Company. +Income +Taxes +Year Ended December 31, +2006 +2005 +2004 +(Dollars in thousands) +Income before income tax +$ +1,043,834 +$ +584,759 +$ +149,147 +Income tax expense +371,267 +212,019 +54,801 +Effective tax rate +35.6 +% +36.3 +% +36.7 +% +30 +The effective tax rate in 2006 is a result of a Federal rate of +35.0% plus an effective state tax rate of 1.4% reduced by +permanent differences between taxable income and book income +(“permanent differences”). The effective tax rate in +2005 is a result of a Federal rate of 35.0% plus an effective +state tax rate of 1.8% reduced by permanent differences. The +effective tax rate in 2004 is a result of a Federal rate of +35.0% and an effective state income tax rate of 1.6% increased +by permanent differences. The permanent differences to our +effective income tax rate in 2006 and 2005 were largely +attributable to the Domestic Production Activities Deduction. +The deduction was enacted as part of the American Jobs Creation +Act of 2004 effective for taxable years after December 31, +2004. The act allows a deduction of 3% in 2005 and 2006, 6% in +2007, 2008 and 2009, and 9% in 2010 and after on the lesser of +qualified production activities income or taxable income. +For tax purposes, we have available at December 31, 2006, +Federal net operating loss carryforwards of approximately +$5 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: 2018 — $1 million and +2019 — $4 million. The alternative minimum tax +credit may be carried forward indefinitely. +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 differences +between the book basis and tax basis in our assets. Deferred tax +assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the year in which those +temporary differences are expected to be settled. As a result of +fully recognizing the benefit of our deferred income taxes, we +incur deferred income tax expense as these benefits are +utilized. We incurred a deferred tax benefit of approximately +$4.1 million in 2006 and a deferred income tax expense of +approximately $17.1 million and $14.8 million for 2005 +and 2004, respectively. +Volatility +of Oil and Natural Gas Prices +Our revenue, profitability and rate of growth are substantially +dependent upon prevailing prices for oil and natural gas, with +respect to all of our operating segments. For many years, oil +and natural gas prices and markets have been volatile. Prices +are affected by market supply and demand factors as well as +international military, political and economic conditions, and +the ability of OPEC, to set and maintain production and price +targets. All of these factors are beyond our control. The +average market price of natural gas has improved from $3.36 in +2002 to $6.94 in 2006, resulting in an increase in demand for +our drilling services. Our average number of rigs operating +increased from 126 in 2002 to 296 in 2006. We expect oil and +natural gas prices to continue to be volatile and to affect our +financial condition and operations and ability to access sources +of capital. A significant decrease in market prices for natural +gas would likely 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 difficulty sustaining profit margins during the downturn +periods. +Impact of +Inflation +We believe that inflation will not have a significant near-term +impact on our financial position. +Recently +Issued Accounting Standards +In June 2006, the FASB issued Interpretation No. 48, +Accounting for Uncertainty in Income Taxes — an +interpretation of FASB Statement No. 109 +(“FIN 48”). FIN 48 clarifies the accounting +for uncertainty in income taxes recognized in an +enterprise’s financial statements and prescribes a +recognition threshold and measurement attribute for the +financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. +FIN 48 is effective for fiscal years beginning after +December 15, 2006 and became effective for the Company as +of January 1, 2007. The implementation of this standard is +not expected to have a material impact in 2007. +31 +In September 2006, the FASB issued Statement No. 157, +Fair Value Measurements (“FAS 157”). +FAS 157 defines fair value, establishes a framework for +measuring fair value in generally accepted accounting +principles, and expands disclosures about fair value +measurement. FAS 157 is effective for financial statements +issued for fiscal years beginning after November 15, 2007 +and interim periods within those fiscal years. FAS 157 will +be effective for the Company in the quarter ending +March 31, 2008. The application of FAS 157 is not +expected to have a material impact to the Company. +In September 2006, the SEC staff issued Staff Accounting +Bulletin No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current +Year Financial Statements (“SAB 108”). +SAB 108 was issued in order to eliminate the diversity of +practice surrounding how public companies quantify financial +statement misstatements. Traditionally, there have been two +widely-recognized methods for quantifying the effects of +financial statement misstatements. The “roll-over” +method focuses primarily on the impact of a misstatement on the +income statement (including the reversing effect of prior year +misstatements) but its use can lead to the accumulation of +misstatements in the balance sheet. The “iron-curtain” +method, on the other hand, focuses primarily on the effect of +correcting the period-end balance sheet with less emphasis on +the reversing effects of prior year errors on the income +statement. The Company currently uses the iron-curtain method +for quantifying identified financial statement misstatements. In +SAB 108, the SEC staff established an approach that +requires quantification of financial statement misstatements +based on the effects of the misstatements on each of the +company’s financial statements and the related financial +statement disclosures. This model is commonly referred to as a +“dual approach” because it requires quantification of +errors under both the iron curtain and the roll-over methods. +The Company applied the provisions of SAB 108 in the +quarter ended December 31, 2006 and there was no impact. +Item 7A. +Quantitative +and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk +associated with borrowings under our credit facility. The +revolving credit facility calls for periodic interest payments +at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at +the prime rate. The applicable rate above LIBOR is based upon +our debt to capitalization ratio. A 5% increase in LIBOR and the +prime rate would result in additional interest expense of +approximately $415,000 based on borrowings outstanding at +December 31, 2006. +We conduct some business in Canadian dollars through our +Canadian land-based drilling operations. The exchange rate +between Canadian dollars and U.S. dollars has fluctuated +during the last several years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and +earnings of our Canadian operations will be reduced and the +value of our Canadian net assets will decline when they are +translated to U.S. dollars. +Item 8. +Financial +Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the +end of Part IV hereof beginning at +page F-1, +Index to Consolidated Financial Statements, and are incorporated +herein by this reference. +Item 9. +Changes +in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2006, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time +32 +periods specified in SEC rules and forms and is accumulated and +reported to our management, including our CEO and CFO, as +appropriate to allow timely decisions regarding required +disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2006, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2006. +Our assessment of the effectiveness of our internal control over +financial reporting as of December 31, 2006 has been +audited by PricewaterhouseCoopers LLP, an independent registered +public accounting firm, as stated in their report which appears +under Item 8 of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +As of December 31, 2005, in our assessment of the +effectiveness of our internal control over financial reporting, +we identified material weaknesses in our internal control over +financial reporting relating to: +1. Control environment. We 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, +financial statements and documents together with forged approval +signatures. This control environment material weakness +contributed to the embezzlement by our former Chief Financial +Officer, Jonathan D. Nelson, of our funds for his own benefit, +and in turn resulted in the restatement of our consolidated +financial statements for the years ended December 31, 2004, +2003 and 2002, each of the quarters of 2004 and 2003, and the +first three quarters of 2005. +2. Controls over property and +equipment. We did not maintain effective controls +over the completeness and accuracy of our accounting for +property and equipment including (i) the timely and +accurate depreciation of all property and equipment, +(ii) the identification 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 reflected in our accounting records. +This control deficiency resulted in certain inaccuracies in our +accounting for property and equipment and in the restatement of +our consolidated financial statements for the years ended +December 31, 2004, 2003 and 2002; each of the quarters of +2004 and 2003; and the first three quarters of 2005. +These material weaknesses are discussed in greater detail in our +Annual Report on +Form 10-K +for the year ended December 31, 2005. +During the fourth quarter of 2006, we completed the +implementation of the following remediation steps to address the +material weakness in our control environment: +• +employees provide formal certifications of information contained +in SEC filings related to their areas of responsibility; +• +senior employees and accounting staff submit annual written +questionnaires with respect to awareness as to questionable +business practices; +• +educational and training programs covering ethics, compliance, +financial reporting, good business practices and fraud awareness +have been provided to employees; +• +additional guidelines were provided to senior management with +respect to their responsibilities for SEC filings, financial +reports, budgets and maintenance of controls over assets and +expenditures; and, +• +annual reporting to the audit committee with respect to these +processes and procedures was added. +33 +Additionally, certain structural changes and processes and +procedures were instituted to increase communications between +the financial reporting and accounting functions and operations +and between financial reporting and accounting functions and +senior management. The internal audit reporting structure was +also revised to provide for enhanced reporting to the audit +committee. +During the fourth quarter of 2006, we completed the +implementation of the following remediation steps to address the +material weakness in our controls over property and equipment: +• +increased coordination between accounting staff and operations +to more promptly identify the impairment or retirement of +drilling equipment undergoing refurbishment or repair; +• +instituted quarterly physical inventories of our drill pipe and +drill collars with comparison of the results of those +inventories to our property records; +• +instituted an annual physical inventory of significant drilling +equipment with comparison of the results of that inventory to +our property records; and, +• +improved procedures to identify property placed in service and +to begin depreciation of those assets when placed in service. +The changes described above are changes in our internal control +over financial reporting during the most recently completed +fiscal quarter that have materially affected, or are reasonably +likely to materially affect, our internal control over financial +reporting. +Item 9B. +Other +Information +On February 20, 2007, the Compensation Committee of the +Board of Directors of Patterson-UTI Energy, Inc. adopted a +bonus compensation program (the “Program”) that would +allocate two-thirds of one percent of the Company’s +consolidated earnings before interest, income taxes and +depreciation, depletion and amortization (“EBITDA”) +for fiscal 2007 (the “Allocated Bonus Amount”) among +the following four executive officers of the Company if the +Company has EBITDA of at least $400 million for fiscal 2007: +• +Mark S. Siegel (Chairman of the Board and Director); +• +Cloyce A. Talbott (President & Chief Executive Officer +and Director) (Messrs. Siegel and Talbott, collectively, the +“Group A Executive Officers”); +• +Kenneth N. Berns (Senior Vice President and Director); and +• +John E. Vollmer III (Senior Vice President — +Corporate Development, Chief Financial Officer and Treasurer) +(Messrs. Berns and Vollmer, collectively, the “Group B +Executive Officers”). +Each Group A Executive Officer would be allocated one-third +of the Allocated Bonus Amount and each Group B Executive +Officer would be allocated one-sixth of the Allocated Bonus +Amount, however, the Compensation Committee expressly retained +the ability to reduce the Allocated Bonus Amount at its +discretion. +34 +PART III +The information required by Part III is omitted from this +Report because we will file a definitive proxy statement +pursuant to Regulation 14A of the Securities Exchange Act +of 1934 no later than 120 days after the end of the fiscal +year covered by this Report and certain information included +therein is incorporated herein by reference. +Item 10. +Directors, +Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 11. +Executive +Compensation. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 12. +Security +Ownership of Certain Beneficial Owners and Management and +Related Stockholder Matters. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 13. +Certain +Relationships, Related Transactions and Director +Independence. +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. +35 +PART IV +Item 15. +Exhibits +and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 +of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts +is filed herewith on +page S-1. +All other financial statement schedules have been omitted +because they are not applicable or the information required +therein is included elsewhere in the financial statements or +notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by +reference herein. +3 +.1 +Restated Certificate of +Incorporation, as amended (filed August 9, 2004 as +Exhibit 3.1 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate +of Incorporation, as amended (filed August 9, 2004 as +Exhibit 3.2 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Amended and Restated Bylaws (filed +March 19, 2002 as Exhibit 3.2 to the Company’s +Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated +January 2, 1997, between Patterson Energy, Inc. and +Continental Stock Transfer & Trust Company (filed +January 14, 1997 as Exhibit 2 to the Company’s +Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement +dated as of October 23, 2001 (filed October 31, 2001 +as Exhibit 3.4 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of +Incorporation, as amended (See Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with +Bear, Stearns and Co. Inc., dated March 25, 1994, as +assigned by REMY Capital Partners III, L.P.(filed +March 19, 2002 as Exhibit 4.3 to the Company’s +Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, +see Exhibits 4.1, 4.2 and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 +Stock Incentive Plan, as amended (filed March 13, 1998 as +Exhibit 10.1 to the Company’s Registration Statement +on +Form S-8 +(File +No. 333-47917) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. +Non-Employee Directors’ Stock Option Plan, as amended +(filed November 4, 1997 as Exhibit 10.1 to the +Company’s Registration Statement on +Form S-8 +(File +No. 333-39471) +and incorporated herein by reference).* +10 +.4 +Amended and Restated Patterson-UTI +Energy, Inc. 2001 Long-Term Incentive Plan (filed +November 27, 2002 as Exhibit 4.4 to Post Effective +Amendment No. 1 to the Company’s Registration +Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Amended +and Restated 1997 Long-Term Incentive Plan (filed July 28, +2003 as Exhibit 4.7 to the Company’s Quarterly Report +on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.6 +Amendment to the Patterson-UTI +Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan +(filed August 9, 2004 as Exhibit 10.7 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.7 +Amended and Restated Patterson-UTI +Energy, Inc. Non-Employee Director Stock Option Plan(filed +July 28, 2003 as Exhibit 4.8 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +36 +10 +.8 +Amended and Restated Patterson-UTI +Energy, Inc. 1996 Employee Stock Option Plan (filed +July 25, 2001 as Exhibit 4.4 to Post-Effective +Amendment No. 1 to the Company’s Registration +Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.9 +Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan, including Form of Executive Officer +Restricted Stock Award Agreement, Form of Executive Officer +Stock Option Agreement, Form of Non-Employee Director Restricted +Stock Award Agreement and Form of Non-Employee Director Stock +Option Agreement (filed June 15, 2005 as Exhibit 10.1 +to the Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.10 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Mark S. Siegel (filed August 9, 2004 as Exhibit 10.1 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.11 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Cloyce A. Talbott (filed August 9, 2004 as +Exhibit 10.2 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.12 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +A. Glenn Patterson (filed August 9, 2004 as +Exhibit 10.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.13 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Kenneth N. Berns (filed August 9, 2004 as Exhibit 10.4 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +John E. Vollmer III (filed August 9, 2004 as +Exhibit 10.6 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.15 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed +on February 4, 2004 as Exhibit 10.2 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.16 +Employment Agreement, effective as +of May 3, 2006 between Patterson-UTI Energy, Inc. and A. +Glenn Patterson (filed on May 5, 2006 as Exhibit 10.1 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended March 31, 2006 and +incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott +(filed on February 4, 2004 as Exhibit 10.4 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Kenneth N. Berns +(filed on February 4, 2004 as Exhibit 10.5 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.19 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and John E. +Vollmer III (filed on February 4, 2004 as +Exhibit 10.7 to the Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.20 +Form of Letter Agreement regarding +termination, effective as of January 29, 2004, entered into +by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, +Kenneth N. Berns and John E. Vollmer III (filed 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).* +10 +.21 +Form of Indemnification Agreement +entered into by Patterson-UTI Energy, Inc. with each of Mark S. +Siegel, Cloyce A. Talbott, A. Glenn Patterson, Kenneth N. Berns, +Robert C. Gist, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, +Nadine C. Smith and John E. Vollmer III (filed +April 28, 2004 as Exhibit 10.11 to the Company’s +Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +37 +10 +.22 +Credit Agreement dated as of +December 17, 2004 among Patterson-UTI Energy, Inc., as the +Borrower, Bank of America, N.A., as administrative agent, L/C +Issuer and a Lender and the other lenders and agents party +thereto (filed on December 23, 2004 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.23 +Commitment Increase and Joinder +Agreement, dated as of August 2, 2006, by and among +Patterson-UTI Energy, Inc., the guarantors party thereto, the +lenders party thereto, and Bank of America, N.A. as +Administrative Agent, L/C Issuer and Lender (filed +August 21, 2006 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K +and incorporated herein by reference). +10 +.24 +Letter Agreement dated +February 6, 2006 between Patterson-UTI Energy, Inc. and +John E. Vollmer III (filed May 1, 2006 as +Exhibit 10.25 to the Company’s Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of +Business Conduct and Ethics for Senior Financial Executives +(filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered +Public Accounting Firm. +31 +.1 +Certification of Chief Executive +Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial +Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive +Officer and Chief Financial Officer pursuant to 18 USC +Section 1350, as adopted pursuant to Section 906 of +the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. +38 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of +Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated +Balance Sheets as of December 31, 2006 and 2005 +F-4 +Consolidated +Statements of Income for the years ended December 31, 2006, +2005 and 2004 +F-5 +Consolidated +Statements of Changes In Stockholders’ Equity for the years +ended December 31, 2006, 2005 and 2004 +F-6 +Consolidated +Statements of Changes In Cash Flows for the years ended +December 31, 2006, 2005 and 2004 +F-7 +Notes to +Consolidated Financial Statements +F-8 +Financial Statement +Schedule +S-1 +F-1 +Report of +Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of +Patterson-UTI Energy, Inc.: +We have completed integrated audits of Patterson-UTI Energy, +Inc.’s consolidated financial statements and of its +internal control over financial reporting as of +December 31, 2006, in accordance with the standards of the +Public Company Accounting Oversight Board (United States). Our +opinions, based on our audits, are presented below. +Consolidated +financial statements and financial statement schedule +In our opinion, the consolidated financial statements listed in +the accompanying index present fairly, in all material respects, +the financial position of Patterson-UTI Energy, Inc. and its +subsidiaries at December 31, 2006 and 2005, and the results +of their operations and their cash flows for each of the three +years in the period ended December 31, 2006 in conformity +with accounting principles generally accepted in the United +States of America. In addition, in our opinion, the financial +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 financial statements. These financial +statements and financial statement schedule are the +responsibility of the Company’s management. Our +responsibility is to express an opinion on these financial +statements and financial statement schedule based on our audits. +We conducted our audits of these statements in accordance with +the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and +perform the audit to obtain reasonable assurance about whether +the financial statements are free of material misstatement. An +audit of financial statements includes examining, on a test +basis, evidence supporting the amounts and disclosures in the +financial statements, assessing the accounting principles used +and significant estimates made by management, and evaluating the +overall financial statement presentation. We believe that our +audits provide a reasonable basis for our opinion. +Internal +control over financial reporting +Also, in our opinion, management’s assessment, included in +Management’s Report on Internal Control over Financial +Reporting appearing under Item 9A, that the Company +maintained effective internal control over financial reporting +as of December 31, 2006, based on criteria established in +Internal Control — Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO), is fairly stated, in all material respects, +based on those criteria. Furthermore, in our opinion, the +Company maintained, in all material respects, effective internal +control over financial reporting as of December 31, 2006, +based on criteria established in Internal Control — +Integrated Framework issued by the COSO. The Company’s +management is responsible for maintaining effective internal +control over financial reporting and for its assessment of the +effectiveness of internal control over financial reporting. Our +responsibility is to express opinions on management’s +assessment and on the effectiveness of the Company’s +internal control over financial reporting based on our audit. We +conducted our audit of internal control over financial reporting +in accordance with the standards of the Public Company +Accounting Oversight Board (United States). Those standards +require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over +financial reporting was maintained in all material respects. An +audit of internal control over financial reporting includes +obtaining an understanding of internal control over financial +reporting, evaluating management’s assessment, testing and +evaluating the design and operating effectiveness of internal +control, and performing such other procedures as we consider +necessary in the circumstances. We believe that our audit +provides a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial 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 +F-2 +assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +PricewaterhouseCoopers LLP +Houston, Texas +February 26, 2007 +F-3 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2006 +2005 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +13,385 +$ +136,398 +Accounts receivable, net of +allowance for doubtful accounts of $7,484 and $2,199 at +December 31, 2006 and 2005, respectively +484,106 +422,002 +Accrued Federal and state income +taxes receivable +5,448 +— +Inventory +43,947 +27,907 +Deferred tax assets, net +48,868 +26,382 +Deposit on equipment purchase +contract +24,746 +— +Other +32,170 +25,168 +Total current assets +652,670 +637,857 +Property and equipment, at cost, +net +1,435,804 +1,053,845 +Goodwill +99,056 +99,056 +Other +4,973 +5,023 +Total assets +$ +2,192,503 +$ +1,795,781 +LIABILITIES AND +STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable: +Trade +$ +138,372 +$ +113,226 +Accrued revenue distributions +15,359 +13,379 +Other +18,424 +5,294 +Accrued Federal and state income +taxes payable +— +11,034 +Accrued expenses +145,463 +112,476 +Total current liabilities +317,618 +255,409 +Borrowings under line of credit +120,000 +— +Deferred tax liabilities, net +187,960 +169,188 +Other +4,459 +4,173 +Total liabilities +630,037 +428,770 +Commitments and contingencies +— +— +Stockholders’ equity: +Preferred stock, par value $.01; +authorized 1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; +authorized 300,000,000 shares with 176,656,401 and +175,909,274 issued and 156,542,512 and 172,441,178 outstanding +at December 31, 2006 and 2005, respectively +1,766 +1,759 +Additional paid-in capital +681,069 +672,151 +Deferred compensation +— +(9,287 +) +Retained earnings +1,346,542 +719,113 +Accumulated other comprehensive +income, net of tax +8,390 +8,565 +Treasury stock, at cost, +20,113,889 shares and 3,468,096 shares at +December 31, 2006 and 2005, respectively +(475,301 +) +(25,290 +) +Total stockholders’ equity +1,562,466 +1,367,011 +Total liabilities and +stockholders’ equity +$ +2,192,503 +$ +1,795,781 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF INCOME +Years Ended December 31, +2006 +2005 +2004 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +2,169,370 +$ +1,485,684 +$ +809,691 +Pressure pumping +145,671 +93,144 +66,654 +Drilling and completion fluids +192,358 +122,011 +90,557 +Oil and natural gas +39,187 +39,616 +33,867 +2,546,586 +1,740,455 +1,000,769 +Operating costs and expenses: +Contract drilling +1,002,001 +776,313 +556,869 +Pressure pumping +77,755 +54,956 +37,561 +Drilling and completion fluids +150,372 +98,530 +76,503 +Oil and natural gas +13,374 +9,566 +7,978 +Depreciation, depletion and +impairment +196,370 +156,393 +122,800 +Selling, general and administrative +55,065 +39,110 +31,983 +Embezzlement costs, net of +recoveries +3,081 +20,043 +19,122 +Other operating expenses +9,404 +4,248 +(514 +) +1,507,422 +1,159,159 +852,302 +Operating income +1,039,164 +581,296 +148,467 +Other income (expense): +Interest income +5,925 +3,551 +1,140 +Interest expense +(1,602 +) +(516 +) +(695 +) +Other +347 +428 +235 +4,670 +3,463 +680 +Income before income taxes and +cumulative effect of change in accounting principle +1,043,834 +584,759 +149,147 +Income tax expense (benefit): +Current +375,373 +194,918 +39,952 +Deferred +(4,106 +) +17,101 +14,849 +371,267 +212,019 +54,801 +Income before cumulative effect of +change in accounting principle +672,567 +372,740 +94,346 +Cumulative effect of change in +accounting principle, net of related income tax expense of $398 +687 +— +— +Net income +$ +673,254 +$ +372,740 +$ +94,346 +Net income per common share: +Basic: +Income before cumulative effect of +change in accounting principle +$ +4.07 +$ +2.19 +$ +0.57 +Cumulative effect of change in +accounting principle +$ +— +$ +— +$ +— +Net income +$ +4.08 +$ +2.19 +$ +0.57 +Diluted: +Income before cumulative effect of +change in accounting principle +$ +4.02 +$ +2.15 +$ +0.56 +Cumulative effect of change in +accounting principle +$ +— +$ +— +$ +— +Net income +$ +4.02 +$ +2.15 +$ +0.56 +Weighted average number of common +shares outstanding: +Basic +165,159 +170,426 +166,258 +Diluted +167,413 +173,767 +169,211 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-In +Deferred +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Compensation +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2003 +82,483 +$ +825 +$ +506,018 +$ +— +$ +290,237 +$ +4,389 +$ +(11,655 +) +$ +789,814 +Issuance of common stock for +acquisition +1,388 +14 +49,462 +— +— +— +— +49,476 +Issuance of restricted stock +189 +2 +6,640 +(6,642 +) +— +— +— +— +Amortization of deferred +compensation expense +— +— +— +1,222 +— +— +— +1,222 +Exercise of stock options and +warrants +2,580 +25 +24,494 +— +— +— +— +24,519 +Tax benefit related to exercise of +stock options +— +— +10,666 +— +— +— +— +10,666 +Foreign currency translation +adjustment (net of tax of $1,716) +— +— +— +— +— +2,961 +— +2,961 +Purchase of treasury stock +— +— +— +— +— +— +(1,482 +) +(1,482 +) +Payment of cash dividend (see +Note 10) +— +— +— +— +(10,021 +) +— +— +(10,021 +) +Effect of +two-for-one +stock split (see Note 10) +84,986 +850 +— +— +(850 +) +— +— +— +Net income +— +— +— +— +94,346 +— +— +94,346 +Balance, December 31, 2004 +171,626 +1,716 +597,280 +(5,420 +) +373,712 +7,350 +(13,137 +) +961,501 +Issuance of restricted stock +305 +3 +8,040 +(8,043 +) +— +— +— +— +Amortization of deferred +compensation expense +— +— +— +2,825 +— +— +— +2,825 +Forfeitures of restricted shares +(65 +) +— +(1,351 +) +1,351 +— +— +— +— +Exercise of stock options +4,043 +40 +43,434 +— +— +— +— +43,474 +Tax benefit related to exercise of +stock options +— +— +24,748 +— +— +— +— +24,748 +Foreign currency translation +adjustment (net of tax of $705) +— +— +— +— +— +1,215 +— +1,215 +Purchase of treasury stock +— +— +— +— +— +— +(12,153 +) +(12,153 +) +Payment of cash dividend (see +Note 10) +— +— +— +— +(27,339 +) +— +— +(27,339 +) +Net income +— +— +— +— +372,740 +— +— +372,740 +Balance, December 31, 2005 +175,909 +1,759 +672,151 +(9,287 +) +719,113 +8,565 +(25,290 +) +1,367,011 +Elimination of deferred +compensation due to change in accounting principle +— +— +(9,287 +) +9,287 +— +— +— +— +Issuance of restricted stock +613 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(47 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +181 +2 +1,944 +— +— +— +— +1,946 +Tax benefit related to exercise of +stock options +— +— +1,087 +— +— +— +— +1,087 +Stock based compensation, net of +cumulative effect of change in accounting principle +— +— +15,179 +— +— +— +— +15,179 +Foreign currency translation +adjustment, (net of tax of $6) +— +— +— +— +— +(175 +) +— +(175 +) +Payment of cash dividend (see +Note 10) +— +— +— +— +(45,825 +) +— +— +(45,825 +) +Purchase of treasury stock +— +— +— +— +— +— +(450,011 +) +(450,011 +) +Net income +— +— +— +— +673,254 +— +— +673,254 +Balance, December 31, 2006 +176,656 +$ +1,766 +$ +681,069 +$ +— +$ +1,346,542 +$ +8,390 +$ +(475,301 +) +$ +1,562,466 +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN CASH FLOWS +Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Cash flows from operating +activities: +Net income +$ +673,254 +$ +372,740 +$ +94,346 +Adjustments to reconcile net +income to net cash provided by operating activities: +Depreciation, depletion and +impairment +196,370 +156,393 +122,800 +Provision for bad debts +5,400 +1,231 +897 +Dry holes and abandonments +4,338 +— +— +Deferred income tax expense +(benefit) +(3,708 +) +17,101 +14,849 +Tax benefit related to exercise of +stock options +— +24,748 +10,666 +Stock based compensation expense +15,179 +2,825 +1,222 +(Gain) loss on disposal of assets +3,819 +(1,253 +) +(1,411 +) +Changes in operating assets and +liabilities, net of business acquired: +Accounts receivable +(67,417 +) +(208,248 +) +(50,682 +) +Federal income taxes +receivable/payable +(16,231 +) +7,068 +15,734 +Inventory and other current assets +(47,406 +) +(9,402 +) +(13,556 +) +Accounts payable +27,184 +60,860 +12,861 +Accrued expenses +32,972 +32,514 +1,555 +Other liabilities +13,416 +3,902 +(6,090 +) +Net cash provided by operating +activities +837,170 +460,479 +203,191 +Cash flows from investing +activities: +Acquisitions, net of cash acquired +— +(73,577 +) +(30,387 +) +Purchases of property and equipment +(597,919 +) +(380,094 +) +(174,589 +) +Proceeds from disposal of property +and equipment +10,934 +12,674 +3,303 +Change in other assets +— +1,766 +(1,766 +) +Net cash used in investing +activities +(586,985 +) +(439,231 +) +(203,439 +) +Cash flows from financing +activities: +Purchase of treasury stock +(450,011 +) +(12,153 +) +(1,482 +) +Dividends paid +(45,825 +) +(27,339 +) +(10,021 +) +Tax benefit related to exercise of +stock options +1,087 +— +— +Proceeds from borrowings under +line of credit +274,000 +— +— +Repayments on line of credit +(154,000 +) +— +— +Line of credit issuance costs +(342 +) +— +(780 +) +Proceeds from exercise of stock +options and warrants +1,946 +43,474 +24,519 +Net cash provided by (used in) +financing activities +(373,145 +) +3,982 +12,236 +Effect of foreign exchange rate +changes on cash +(53 +) +(1,203 +) +(100 +) +Net increase (decrease) in cash +and cash equivalents +(123,013 +) +24,027 +11,888 +Cash and cash equivalents at +beginning of year +136,398 +112,371 +100,483 +Cash and cash equivalents at end +of year +$ +13,385 +$ +136,398 +$ +112,371 +Supplemental disclosure of cash +flow information: +Net cash paid during the year for: +Interest expense +$ +(1,278 +) +$ +(418 +) +$ +(245 +) +Income taxes +(377,847 +) +(156,709 +) +(12,500 +) +The accompanying notes are an integral part of these +consolidated financial statements. +F-7 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., together with its wholly-owned subsidiaries, (collectively +referred to herein as “Patterson-UTI” or the +“Company”) is a leading provider of onshore contract +drilling services to major and independent oil and natural gas +operators in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +South Dakota and Western Canada. The Company provides pressure +pumping services to oil and natural gas operators primarily in +the Appalachian Basin. The Company provides drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore 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. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. The Company has +no controlling financial interests in any entity that is not a +wholly-owned subsidiary which would require consolidation. +The U.S. dollar is the functional currency for all of the +Company’s operations except for its Canadian operations, +which use the Canadian dollar as their functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +On April 28, 2004, the Company’s Board of Directors +authorized a +two-for-one +stock split in the form of a stock dividend which was +distributed on June 30, 2004 to holders of record on +June 14, 2004. At June 30, 2004, an adjustment was +made to reclassify an amount from retained earnings to common +stock to account for the par value of the common stock issued as +a stock dividend. This adjustment had no overall effect on +equity. Historical net income per common share amounts included +in the Statements of Income and elsewhere in these financial +statements have been presented as if the +two-for-one +stock split had occurred on January 1, 2004. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting, as described +below. The Company follows the +percentage-of-completion +method of accounting for footage and daywork contract drilling +arrangements. Under the +percentage-of-completion +method, management estimates are relied upon in the +determination of the total estimated expenses to be incurred +drilling the well. Due to the nature of turnkey contract +drilling arrangements and risks therein, the Company follows the +completed contract method of accounting for such arrangements. +Under this method, all drilling 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 — 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 +F-8 +existing in the Company’s accounts receivable. The Company +reviews the adequacy of its allowance for doubtful accounts +monthly. Significant individual accounts receivable balances and +balances which have been outstanding greater than 90 days +are reviewed individually for collectibility. Account balances, +when determined to be uncollectible, are charged against the +allowance. +Inventories — Inventories consist primarily of +chemical products to be used in conjunction with the +Company’s drilling and completion fluids and pressure +pumping activities. The inventories are stated at the lower of +cost or market, determined by the +first-in, +first-out method. +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change when +equipment becomes idle. The estimated useful lives, in years, +are defined below. +Useful Lives +Drilling rigs and related equipment +2-15 +Office furniture +3-10 +Buildings +15-20 +Automotive equipment +3-7 +Other +3-12 +Oil and natural gas properties — Oil and +natural gas properties are accounted for using the successful +efforts method of accounting. Under the successful efforts +method of accounting, exploration costs which result in the +discovery of oil and natural gas reserves and all development +costs are capitalized to the appropriate well. Exploration costs +which do not result in discovering oil and natural gas reserves +are charged to expense when such 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 whether sufficient +progress is being made in assessing the reserves and the +economic operating viability of the respective projects. If no +progress has been made in assessing the reserves and the +economic operating viability of a project after one year +following the completion of drilling, the Company considers the +costs of the well to be impaired and recognizes the costs as +expense. Geological and geophysical costs, including seismic +costs, and costs to carry and retain undeveloped properties are +charged to expense when incurred. The capitalized costs of both +developmental and successful exploratory type wells, consisting +of lease and well equipment, lease acquisition costs and +intangible development costs, are depreciated, depleted and +amortized on the +units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves of each respective field. The Company reviews its +proved oil and natural gas properties for impairment when an +event occurs such as downward revisions in reserve estimates or +decreases in oil and natural gas prices. Proved properties are +grouped by field and undiscounted cash flow estimates are +provided by an independent petroleum engineer. If the net book +value of a field exceeds its undiscounted cash flow estimate, +impairment expense is measured and recognized as the difference +between its net book value and discounted cash flow. Unproved +oil and natural gas properties are reviewed quarterly to +determine impairment. The Company’s intent to drill, lease +expiration and abandonment of area are considered. Assessment of +impairment is made on a +lease-by-lease +basis. If an unproved property is determined to be impaired, +costs related to that property are expensed. +Goodwill — Goodwill is considered to have an +indefinite 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. +F-9 +Depreciation, depletion and impairment — The +following table summarizes depreciation, depletion and +impairment expense for 2006, 2005 and 2004 (in millions): +2006 +2005 +2004 +Depreciation expense +$ +181.6 +$ +141.7 +$ +109.4 +Depletion expense +9.8 +10.3 +10.1 +Amortization expense +— +— +0.1 +Impairment of oil and natural gas +properties +5.0 +4.4 +3.2 +Total +$ +196.4 +$ +156.4 +$ +122.8 +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Retirements — Upon disposition or retirement of +property and equipment, the cost and related accumulated +depreciation are removed and any resulting gain or loss is +credited or charged to operations. +Net income per common share — The Company +provides a dual presentation of its net income per common share; +Basic net income per common share (“Basic EPS”) and +Diluted net income per common share (“Diluted EPS”). +Basic EPS excludes dilution and is computed by dividing net +income by the weighted average number of unrestricted common +shares outstanding during the year. Diluted EPS is based on the +weighted average number of common shares outstanding plus the +impact of dilutive instruments, including stock options, +warrants and restricted shares using the treasury stock method. +The following table presents information necessary to calculate +net income per share for the years ended December 31, 2006, +2005 and 2004 as well as cash dividends per share paid and +potentially dilutive securities excluded from the weighted +average number of diluted common shares outstanding as their +inclusion would have been anti-dilutive (in thousands, except +per share amounts): +2006 +2005 +2004 +Net income +$ +673,254 +$ +372,740 +$ +94,346 +Weighted average number of +unrestricted common shares outstanding +165,159 +170,426 +166,258 +Basic net income per common share +$ +4.08 +$ +2.19 +$ +0.57 +Weighted average number of +unrestricted common shares outstanding +165,159 +170,426 +166,258 +Dilutive effect of stock options +and restricted shares +2,254 +3,341 +2,953 +Weighted average number of diluted +common shares outstanding +167,413 +173,767 +169,211 +Diluted net income per common share +$ +4.02 +$ +2.15 +$ +0.56 +Cash dividends per common share +$ +0.28 +$ +0.16 +$ +0.06 +Potentially dilutive securities +excluded as anti-dilutive +800 +— +640 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. +Stock based compensation — Prior to +January 1, 2006, the Company accounted for stock based +compensation related to employee stock options and shares of +restricted stock using the recognition and measurement +principles of +F-10 +APB Opinion No. 25, Accounting for Stock Issued to +Employees (“APB 25”), and related +interpretations. Under the provisions of APB 25, expense +associated with stock option grants was measured based on the +intrinsic value of the option at the date of grant and expense +associated with restricted stock grants was measured based on +the fair value of the shares at the date of grant. Reductions in +compensation expense associated with awards that were forfeited +prior to vesting were recognized as those grants were forfeited. +Effective January 1, 2006, the Company adopted the +provisions of Financial Accounting Standards Board Statement +No. 123(R), Accounting for Stock-Based Compensation +(“SFAS 123(R)”). SFAS 123(R) requires the +recognition of expense associated with the grant of both stock +options and restricted stock based on the estimated fair value +of the options or restricted stock at the date of grant, net of +estimated forfeitures. +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit, money market funds and investment grade municipal and +commercial bonds with original maturities of 90 days or +less. +Recently Issued Accounting Standards — In June +2006, the FASB issued Interpretation No. 48, Accounting +for Uncertainty in Income Taxes — an interpretation of +FASB Statement No. 109 (“FIN 48”). +FIN 48 clarifies the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribes a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. +FIN 48 is effective for fiscal years beginning after +December 15, 2006 and became effective for the Company as +of January 1, 2007. The implementation of this standard is +not expected to have a material impact in 2007. +In September 2006, the FASB issued Statement No. 157, +Fair Value Measurements (“FAS 157”). +FAS 157 defines fair value, establishes a framework for +measuring fair value in generally accepted accounting +principles, and expands disclosures about fair value +measurement. FAS 157 is effective for financial statements +issued for fiscal years beginning after November 15, 2007 +and interim periods within those fiscal years. FAS 157 will +be effective for the Company in the quarter ending +March 31, 2008. The application of FAS 157 is not +expected to have a material impact to the Company. +In September 2006, the SEC staff issued Staff Accounting +Bulletin No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current +Year Financial Statements (“SAB 108”). +SAB 108 was issued in order to eliminate the diversity of +practice surrounding how public companies quantify financial +statement misstatements. Traditionally, there have been two +widely-recognized methods for quantifying the effects of +financial statement misstatements. The “roll-over” +method focuses primarily on the impact of a misstatement on the +income statement (including the reversing effect of prior year +misstatements) but its use can lead to the accumulation of +misstatements in the balance sheet. The “iron-curtain” +method, on the other hand, focuses primarily on the effect of +correcting the period-end balance sheet with less emphasis on +the reversing effects of prior year errors on the income +statement. The Company currently uses the iron-curtain method +for quantifying identified financial statement misstatements. In +SAB 108, the SEC staff established an approach that +requires quantification of financial statement misstatements +based on the effects of the misstatements on each of the +company’s financial statements and the related financial +statement disclosures. This model is commonly referred to as a +“dual approach” because it requires quantification of +errors under both the iron curtain and the roll-over methods. +The Company applied the provisions of SAB 108 in the +quarter ended December 31, 2006 and there was no impact. +Reclassifications — Certain reclassifications +have been made to the 2005 and 2004 consolidated financial +statements in order for them to conform with the 2006 +presentation. +2. +Acquisitions +2005 +Acquisitions +Key Energy Services, Inc. — On +January 15, 2005, the Company purchased land drilling +assets from Key Energy Services, Inc. for $61.8 million. +The assets included 25 active and 10 stacked land-based drilling +rigs, related drilling equipment, yard facilities and a rig +moving fleet consisting of approximately 45 trucks and 100 +trailers. The transaction was accounted for as an acquisition of +assets and the purchase price was allocated among the assets +acquired based on their estimated fair market values. +F-11 +Other — On June 17, 2005, the Company +acquired one land-based drilling rig for $3.6 million and +on September 29, 2005, the Company acquired five 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. — 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 outstanding shares of TMBR. +Operations of TMBR subsequent to February 11, 2004, are +included in the Company’s consolidated financial +statements. The transaction was accounted for as a business +combination and the purchase price was allocated among the +assets acquired and liabilities assumed based on their estimated +fair market values. The assets of TMBR included +18 land-based drilling rigs and related equipment, shop +facilities, equipment yards and oil and natural gas properties. +The purchase price was calculated as follows (in thousands, +except per share data and exchange ratio): +Cash of $9.09 per share for +the 4,447 TMBR shares outstanding at February 11, 2004, +excluding the 1,059 TMBR shares owned by Patterson-UTI +$ +40,423 +Patterson-UTI shares issued at +$17.82 per share (4,447 TMBR shares X .624332 exchange +ratio X $17.82) +49,476 +1,059 TMBR shares previously +acquired by the Company +19,771 +Acquisition costs +10,511 +Less: Cash acquired +(7,909 +) +Total purchase price +$ +112,272 +The purchase price was allocated among assets acquired and +liabilities assumed based on their estimated fair market values +as follows (in thousands): +Current assets +$ +7,181 +Property and equipment +60,784 +Other long term assets +172 +Deferred tax assets +13,080 +Goodwill +48,020 +Current liabilities +(7,080 +) +Other long term liabilities +(1,090 +) +Deferred tax liability +(8,795 +) +Total purchase allocation +$ +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. +F-12 +The following represents pro-forma unaudited financial +information as if the acquisition had been completed on +January 1, 2004 (in thousands, except per share amounts): +2004 +Revenue +$ +1,005,357 +Income before cumulative effect of +change in accounting principle +94,047 +Net income +94,047 +Earnings per share: +Basic +$ +0.57 +Diluted +$ +0.56 +3. +Comprehensive +Income +The following table illustrates the Company’s comprehensive +income including the effects of foreign currency translation +adjustments for the years ended December 31, 2006, 2005 and +2004 (in thousands): +2006 +2005 +2004 +Net income +$ +673,254 +$ +372,740 +$ +94,346 +Other comprehensive income: +Foreign currency translation +adjustment related to Canadian operations, net of tax +(175 +) +1,215 +2,961 +Comprehensive income +$ +673,079 +$ +373,955 +$ +97,307 +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2006 and 2005 (in thousands): +2006 +2005 +Equipment +$ +2,135,567 +$ +1,633,911 +Oil and natural gas properties +85,143 +79,079 +Buildings +30,987 +22,490 +Land +7,507 +5,611 +2,259,204 +1,741,091 +Less accumulated depreciation and +depletion +(823,400 +) +(687,246 +) +$ +1,435,804 +$ +1,053,845 +5. +Goodwill +Goodwill is evaluated annually to determine if the fair value of +the asset has decreased below its carrying value. At +December 31, 2006 the Company performed its annual goodwill +evaluation and determined that no adjustment to impair goodwill +was necessary. Goodwill as of December 31, 2006 and 2005 +included $89,092 in the contract drilling segment and $9,964 in +the drilling and completion fluids segment. For purposes of +impairment testing, goodwill is evaluated at the reporting unit +level. The Company’s reporting units for impairment testing +have been determined to be its operating segments. There were no +changes to goodwill during the years ended December 31, +2006 and 2005. +F-13 +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2006 and 2005 (in thousands): +2006 +2005 +Salaries, wages, payroll taxes and +benefits +$ +42,751 +$ +33,816 +Workers’ compensation +liability +67,615 +47,107 +Sales, use and other taxes +11,043 +9,484 +Insurance, other than +workers’ compensation +13,328 +11,365 +Other +10,726 +10,704 +$ +145,463 +$ +112,476 +7. +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 2006 and 2005 +(in thousands): +2006 +2005 +Balance at beginning of year +$ +1,725 +$ +2,358 +Liabilities incurred +154 +101 +Liabilities settled +(104 +) +(808 +) +Accretion expense +54 +74 +Asset retirement obligation at end +of year +$ +1,829 +$ +1,725 +8. +Borrowings +Under Line of Credit +The Company entered into a five-year, $200 million +unsecured revolving line of credit (“LOC”) in December +2004. Interest is to be paid on outstanding LOC balances at a +floating rate ranging from LIBOR plus 0.625% to 1.0% or the +prime rate. Any outstanding borrowings must be repaid at +maturity on December 16, 2009. This arrangement includes +various fees, including a commitment fee on the average daily +unused amount (0.15% at December 31, 2006). 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. +On August 2, 2006, the Company entered into an agreement to +amend the LOC. In connection with this amendment, the borrowing +capacity under this LOC was increased to $375 million. No +significant changes were made to the terms of the LOC including +the interest to be paid on outstanding balances and financial +covenants. As of December 31, 2006, the Company had +borrowed $120 million under the LOC and $60 million in +letters of credit were outstanding. As a result, the Company had +available borrowing capacity of $195 million at +December 31, 2006. The weighted average interest rate on +borrowings outstanding at December 31, 2006 was 6.92%. +9. +Commitments, +Contingencies and Other Matters +Commitments — The Company maintains letters of +credit in the aggregate amount of approximately $60 million +for the benefit of various insurance companies as collateral for +retrospective premiums and retained losses which may become +payable under the terms of the underlying insurance contracts. +These letters of credit are typically renewed annually. No +amounts have been drawn under the letters of credit. +As of December 31, 2006, the Company has signed +non-cancelable commitments to purchase approximately +$297 million of equipment to be received throughout 2007. +This amount excludes a $24.7 million deposit that was paid +during 2006 pursuant to an agreement that was entered into to +purchase rig components to be used in the +F-14 +construction of 15 new land drilling rigs. This payment is +presented as a deposit on equipment purchase contract in the +consolidated balance sheet at December 31, 2006. +Contingencies — The Company’s contract +services and oil and natural gas exploration and production +operations are subject to inherent risks, including blowouts, +cratering, fire and explosions which could result in personal +injury or death, suspended drilling operations, damage to, or +destruction of equipment, damage to producing formations and +pollution or other environmental hazards. +As a protection against these hazards, the Company maintains +general liability insurance coverage of $2.0 million per +occurrence with $4.0 million of aggregate coverage and +excess liability and umbrella coverages up to $100 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. +The Company believes it is adequately insured for public +liability and property damage to others with respect to its +operations. However, such insurance may not be sufficient to +protect the Company against liability for all consequences of +well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its rigs. However, it does not +cover the full replacement cost of the rigs and the Company does +not carry insurance against loss of earnings resulting from such +damage or loss. +Net income for the year ended December 31, 2005 includes a +charge of $4.2 million related to the financial failure of +a workers’ compensation insurance carrier that had provided +coverage for the Company in prior years. +In November 2005, the Company discovered that its former Chief +Financial Officer, Jonathan D. Nelson (“Nelson”), had +fraudulently diverted approximately $77.5 million in +Company funds for his own benefit. As a result, the Audit +Committee of the Board of Directors commenced an investigation +into Nelson’s activities and retained independent counsel +and independent forensic accountants to assist with the +investigation. Nelson has been sentenced and is serving a term +of imprisonment arising out of his embezzlement. A receiver has +been appointed to take control of and liquidate the assets of +Nelson in connection with his embezzlement of Company funds. The +receiver is in the process of seeking court approval for a plan +of distribution of the assets recovered by the receiver and the +proceeds thereof, which total approximately $40 million. +While the Company believes it has a claim for at least the full +amount of funds embezzled from the Company, other creditors have +asserted or may assert claims with respect to the assets held by +the receiver. +In December 2005, two purported derivative actions were filed in +Texas state court in Scurry County, Texas and in May 2006, a +derivative action was filed in federal court in Lubbock, Texas, +in each case, against the Company’s directors, alleging +that the directors breached their fiduciary duties to the +Company as a result of alleged failure to timely discover the +embezzlement of approximately $77.5 million by its former +CFO, Jonathan D. Nelson. 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 were stayed pending +completion of the work of the special litigation committee. The +lawsuits sought recovery on behalf of and for the Company and +did not seek recovery from the Company. In November 2006, the +parties to all three of the derivative actions reached an +agreement to settle the actions. After a preliminary hearing and +notice to the Company’s stockholders, the state court held +a hearing, approved the settlement, which required the +implementation of certain corporate governance measures, and +signed a final judgment on December 29, 2006. As +contemplated by the settlement agreement, the federal court +entered a final judgment on January 10, 2007. Pursuant to +the terms of the settlement, the Company will pay a net amount +of $230,000 to the attorneys for the plaintiffs in the suits. +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 +effect on its financial condition. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer and two Senior Vice Presidents (the “Key +Employees”). Each Change in Control Agreement generally has +a three-year term with automatic twelve month renewals unless +the Company notifies the Key Employee at least ninety days +before the end of such renewal period that the term will not be +extended. If a change in control of the Company occurs during +the term of the agreement and the Key Employee’s employment +is terminated +F-15 +(i) by the Company other than for cause or other than +automatically as a result of death, disability or retirement or +(ii) by the Key Employee for good reason (as those terms +are defined in the Change in Control Agreements), then the Key +Employee shall be entitled to, among other things, +• +bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer) or 1.5 times (in the case of +the Senior Vice Presidents) of the sum of (i) the highest +annual salary in effect for such Key Employee and (ii) the +average of the three annual bonuses earned by the Key Employee +for the three fiscal years preceding the termination +date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) 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 benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +10. +Stockholders’ +Equity +The Company has granted restricted shares of the Company’s +common stock (“Restricted Shares”) to certain key +employees under the Patterson-UTI Energy, Inc. 1997 Long-Term +Incentive Plan, as amended, and the Patterson-UTI Energy, Inc. +2005 Long-Term Incentive Plan. As required by SFAS 123(R), +the Restricted Shares were valued based upon the market price of +the Company’s common stock on the date of the grant. The +restrictions on these shares lapse at various dates through 2010. +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 2004, the Company purchased 100,000 shares of its +common stock under this program in the open market for +approximately $1.5 million. During 2005, the Company +purchased 355,000 shares of its common stock under this +program in the open market for approximately $12.2 million. +On March 27, 2006, the Company’s Board of Directors +increased the stock buyback program to allow for future +purchases of up to $200 million of the Company’s +outstanding common stock. During the second quarter of 2006, the +Company completed the purchase of 6,704,800 shares of its +common stock under this program in the open market at a cost of +approximately $200 million. On August 2, 2006, the +Company’s Board of Directors again increased the stock +buyback program to allow for future purchases of up to +$250 million of the Company’s outstanding common +stock. During the remainder of 2006, the Company purchased an +additional 9,940,542 shares of its common stock under this +program in the open market at a cost of approximately +$250 million. Shares purchased under the stock buyback +program have been accounted for as treasury stock. +On April 28, 2004, the Company’s Board of Directors +authorized a +two-for-one +stock split in the form of a stock dividend which was +distributed on June 30, 2004 to holders of record on +June 14, 2004. In connection with the +two-for-one +stock split, an adjustment was made to reclassify an amount from +retained earnings to common stock to account for the par value +of the common stock issued as a stock dividend. This adjustment +had no overall effect on equity. Historical net income per +common share amounts included in the Consolidated Statements of +Income and elsewhere in these financial statements have been +presented as if the +two-for-one +stock split had occurred on January 1, 2004. +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, September 1, 2004 and December 1, 2004. Total +dividends paid in 2004 were approximately $10.0 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. 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. On March 2, 2006, the +Company’s Board of Directors approved a cash dividend on +its common stock in the amount of $0.04 per share +F-16 +which was paid on March 30, 2006. On April 26, 2006, +the Company’s Board of Directors approved an increase in +its quarterly cash dividend from $0.04 to $0.08 on each +outstanding share of its common stock. Cash dividends of +$0.08 per share were paid on June 30, 2006, +September 29, 2006 and December 29, 2006. Total cash +dividends in 2006 were approximately $45.8 million. The +amount and timing of all future dividend payments is subject to +the discretion of the Board of Directors and will depend upon +business conditions, results of operations, financial condition, +terms of the Company’s credit facilities and other factors. +In February 2004, the Company completed its acquisition of TMBR +in which one of its wholly-owned subsidiaries acquired 100% of +the outstanding shares of TMBR for a net cash payment of +$32.5 million ($40.4 million paid to TMBR shareholders +less $7.9 million in cash acquired in the transaction) and +the issuance of 2.78 million shares of the Company’s +common stock valued at $17.82 per share (adjusted to reflect the +two-for-one +stock split on June 30, 2004). The assets of TMBR included +18 land-based drilling rigs and related equipment, shop +facilities, equipment yards and their oil and natural gas +properties. The transaction was accounted for as a business +combination and the purchase price was allocated among the +assets acquired and liabilities assumed based on their estimated +fair market values (see Note 2). +11. +Stock-based +Compensation +The Company adopted FASB 123(R) on January 1, 2006 and +recognizes the cost of share-based payments under the +fair-value-based method. The Company uses share-based payments +to compensate employees and non-employee directors. All awards +have been equity instruments in the form of stock options or +restricted stock awards and include only service conditions. The +Company issues shares of common stock when vested stock option +awards are exercised and when restricted stock awards are +granted. For the year ended December 31, 2006, the Company +recognized $16.3 million in stock-based compensation +expense and a related income tax benefit of approximately +$5.8 million and recognized a benefit in the form of a +cumulative effect of change in accounting principle associated +with the adoption of FAS 123(R) of $1.1 million, with +a related tax expense of $398,000. As a result of the adoption +of FAS 123(R) in 2006, operating income and income before +income taxes was reduced by $8.4 million. Net income was +reduced by $4.7 million. Basic EPS and Diluted EPS were +reduced by $0.03 per share as a result of the adoption of +FAS 123(R). +During 2005, the Company’s shareholders approved the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the +“2005 Plan”) and the Board of Directors adopted a +resolution that no future grants would be made under any of the +Company’s other previously existing plans. The +Company’s share-based compensation plans at +December 31, 2006 follow: +Options & +Shares +Restricted +Shares +Authorized +Shares +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan +6,250,000 +1,540,252 +4,140,197 +Patterson-UTI Energy, Inc. Amended +and Restated 1997 Long-Term Incentive Plan, as amended +(“1997 Plan”) +— +5,090,885 +— +Amended and Restated Patterson-UTI +Energy, Inc. 2001 Long-Term Incentive Plan (“2001 +Plan”) +— +762,559 +— +Amended and Restated Non-Employee +Director Stock Option Plan of Patterson-UTI Energy, Inc. +(“Non-Employee Director Plan”) +— +150,000 +— +Amended and Restated Patterson-UTI +Energy, Inc. 1996 Employee Stock Option Plan (“1996 +Plan”) +— +95,800 +— +Patterson-UTI Energy, Inc., 1993 +Incentive Stock Plan, as amended (“1993 Plan”) +— +123,800 +— +F-17 +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over 1 year for non-employee +directors and 3 to 4 years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2006, only +non-incentive stock options and restricted stock awards had been +granted under the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted Stock +Awards granted under the 1997 Plan typically vest over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Options granted under the Non-Employee Director Plan vest on the +first anniversary of the option grant. Non-Employee Director +Plan options have five year terms. All options were granted with +an exercise price equal to the fair market value of the related +common stock at the time of grant. +Options granted under the 1996 plan typically vest over one, +four or five years as dictated by the Compensation Committee. +These options have terms of no more than 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. +Options granted under the 1993 Plan typically typically vest +over five years as dictated by the Compensation Committee. These +options have terms of no more than 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. +Stock Options — The Company accounted for all +stock options under the intrinsic value method prior to +January 1, 2006. Accordingly, no compensation expense was +recognized in prior periods for stock options because they had +no intrinsic value when granted as exercise prices were equal to +the grant date market value of the related common stock. The +Modified Prospective Application (“MPA”) method is +being applied to transition from the intrinsic value method to +the fair-value-based method for stock options. The effects of +the application of the MPA method follow: +• +Previously reported amounts and disclosures are not affected. +• +Compensation cost, net of estimated forfeitures for the unvested +portion of awards outstanding at January 1, 2006, is +recognized under the fair-value-based method as the awards vest. +Compensation cost is based on the grant-date estimated fair +value of stock options as calculated for the Company’s +previously reported pro forma disclosures under FASB Statement +No. 123, Accounting for Stock-Based Compensation +(“FAS 123”). +• +The fair-value based method is applied to new awards and to any +awards outstanding at January 1, 2006 that are modified, +repurchased or cancelled after that date. +F-18 +The Company estimates grant date fair values of stock options +using the Black-Scholes-Merton valuation model +(“Black-Scholes”), except for stock options granted +prior to 1996 that are not subject to FAS 123(R) and were +not subject to FAS 123 pro forma disclosures. Volatility +assumptions are based on the historic volatility of the +Company’s common stock over the most recent period equal to +the expected term of the options as of the date the options were +granted. The expected term assumptions are based on the +Company’s experience with respect to employee stock option +activity. Dividend yield assumptions are based on the expected +dividends at the time the options were granted. The risk-free +interest rate assumptions are determined by reference to United +States Treasury yields. Weighted-average assumptions used to +estimate grant date fair values for stock options granted in the +years ended December 31, 2006, 2005 and 2004 follow: +2006 +2005 +2004 +Volatility +33.18 +% +26.95 +% +36.84 +% +Expected term (in years) +4.00 +4.00 +3.84 +Dividend yield +1.09 +% +0.65 +% +0.06 +% +Risk-free interest rate +4.87 +% +3.84 +% +3.22 +% +Stock option activity for the year ended December 31, 2006 +follows: +Weighted +Average +Exercise +Shares +Price +Outstanding at beginning of year +6,338,044 +$ +14.37 +Granted +800,000 +$ +28.54 +Exercised +(180,726 +) +$ +10.77 +Forfeited +(17,000 +) +$ +10.94 +Expired +(4,389 +) +$ +9.28 +Cancelled(a) +(360,833 +) +$ +14.83 +Outstanding at end of year +6,575,096 +$ +16.18 +Exercisable at end of year +5,392,263 +$ +13.92 +(a) +Represents vested stock options held by the former CFO which +were cancelled by the Company’s Board of Directors. +Options outstanding at December 31, 2006 have an aggregate +intrinsic value of approximately $51.4 million and have a +weighted-average remaining contractual term of 6.21 years. +Options exercisable at December 31, 2006 have an aggregate +intrinsic value of approximately $50.6 million and have a +weighted-average remaining contractual term of 5.60 years. +Additional information with respect to options granted and +exercised during the years ended December 31, 2006, 2005 +and 2004 follows: +2006 +2005 +2004 +Weighted-average grant-date fair +value of stock options granted (per share) +$ +8.62 +$ +6.33 +$ +6.25 +Aggregate intrinsic value of stock +options exercised (in thousands) +$ +3,377 +$ +73,467 +$ +41,171 +F-19 +As of December 31, 2006, options to purchase +1,182,833 shares were outstanding and not vested. +Substantially all of these non-vested options are expected to +ultimately vest. Additional information as of December 31, +2006 with respect to these options that are expected to vest +follows: +Aggregate intrinsic value +$ +766,000 +Weighted-average remaining +contractual term +8.98 years +Weighted-average remaining +expected term +2.99 years +Weighted-average remaining vesting +period +1.99 years +Unrecognized compensation cost +$ +8.2 million +Restricted Stock — Under all restricted stock +awards to date, shares were issued when granted, nonvested +shares are subject to forfeiture for failure to fulfill service +conditions and nonforfeitable dividends are paid on nonvested +restricted shares. Restricted stock awards prior to +January 1, 2006 were valued at the grant date market value +of the underlying common stock, recognized as contra equity +deferred compensation and amortized to expense under the +“graded-vesting” method. Implementation of +FAS 123(R) did not change the accounting for the +Company’s nonvested stock awards, except as follows: +• +Prior to January 1, 2006, forfeitures were recognized as +they occurred; +• +From January 1, 2006 forward, forfeitures are estimated in +the determination of periodic compensation cost; +• +Contra equity deferred compensation was reversed against +paid-in-capital +at January 1, 2006; and +• +Compensation expense is recognized as attributed to each period. +The Company uses the “graded-vesting” attribution +method to determine periodic compensation cost from restricted +stock awards. +Restricted stock activity for the year ended December 31, +2006 follows: +Weighted- +Average Grant +Shares +Date Fair Value +Outstanding at beginning of year +623,150 +$ +21.44 +Granted +613,400 +$ +30.46 +Vested +(1,351 +) +$ +14.73 +Forfeited +(46,999 +) +$ +26.00 +Outstanding at end of year +1,188,200 +$ +25.92 +As of December 31, 2006, approximately +1,059,000 shares of nonvested restricted stock outstanding +are expected to vest. Additional information as of +December 31, 2006 with respect to these shares that are +expected to vest follows: +Aggregate intrinsic value +$ +24.6 million +Weighted-average remaining vesting +period +2.51 years +Unrecognized compensation cost +$ +16.0 million +Dividends on Equity Awards — Nonforfeitable +dividends paid on equity awards are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of equity awards expected to vest. +• +Dividends are recognized as additional compensation cost for the +portion of equity awards that are not expected to vest or that +ultimately do not vest. +Vesting expectations, in regard to these dividend payments, +correspond with forfeiture assumptions used to recognize +compensation cost. +F-20 +Prior Period Pro Forma Disclosures — Prior to +January 1, 2006, the Company accounted for share-based +compensation under the intrinsic value method. Other than the +restricted stock discussed above, no additional share-based +compensation expense was reflected in earnings prior to +January 1, 2006 since the exercise price was equal to the +grant-date market value of the underlying common stock for all +stock options granted prior to that date. The effect of +share-based compensation, as if the Company had applied the +fair-value-based method proscribed by FAS 123, on net +income and earnings per share for the yeas ended +December 31, 2005 and 2004 (in thousands, except per share +amounts): +2005 +2004 +Net income, as reported +$ +372,740 +$ +94,346 +Add back: Share-based employee +compensation cost, net of related tax effects, included in net +income as reported +1,795 +773 +Deduct: Share-based employee +compensation cost, net of related tax effects, that would have +been included in net income if the fair-value-based method had +been applied to all awards +(11,119 +) +(12,304 +) +Pro-forma net income +$ +363,416 +$ +82,815 +Net income per common share: +Basic, as reported +$ +2.19 +$ +0.57 +Basic, pro-forma +$ +2.13 +$ +0.50 +Diluted, as reported +$ +2.15 +$ +0.56 +Diluted, pro-forma +$ +2.11 +$ +0.49 +12. +Leases +The Company incurred rent expense of $31.8 million, +$22.5 million and $17.8 million, for the years 2006, +2005 and 2004, respectively. The Company’s obligations +under non-cancelable operating lease agreements are not material +to the Company’s operations. +F-21 +13. +Income +Taxes +Components of the income tax provision applicable for Federal, +state and foreign income taxes for the years ended +December 31, 2006, 2005 and 2004 are as follows (in +thousands): +2006 +2005 +2004 +Federal income tax expense +(benefit): +Current +$ +344,395 +$ +174,635 +$ +32,686 +Deferred +(5,851 +) +14,182 +12,366 +338,544 +188,817 +45,052 +State income tax expense: +Current +21,371 +13,045 +2,031 +Deferred +1,392 +1,431 +1,555 +22,763 +14,476 +3,586 +Foreign income tax expense: +Current +9,607 +7,238 +5,235 +Deferred +353 +1,488 +928 +9,960 +8,726 +6,163 +Total: +Current +375,373 +194,918 +39,952 +Deferred +(4,106 +) +17,101 +14,849 +Total income tax expense +$ +371,267 +$ +212,019 +$ +54,801 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2006, 2005 and 2004 is summarized as follows: +2006 +2005 +2004 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.4 +1.8 +1.6 +Permanent differences +(0.8 +) +(0.6 +) +0.4 +Other, net +0.0 +0.1 +(0.3 +) +Effective tax rate +35.6 +% +36.3 +% +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 differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2006 to be +realized as a result of the reversal during the carryforward +period of existing taxable temporary differences giving rise to +deferred tax liabilities and the generation of taxable income in +the carryforward period; therefore, no valuation allowance is +necessary. +F-22 +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December +December +December +January +31, +Net +31, +Net +31, +Net +1, +2006 +Change +2005 +Change +2004 +Change +2004 +Deferred tax assets: +Current: +Federal net operating loss +carryforwards +$ +1,870 +$ +— +$ +1,870 +$ +— +$ +1,870 +$ +1,870 +$ +— +Workers’ compensation allowance +26,363 +6,902 +19,461 +4,584 +14,877 +1,545 +13,332 +Embezzlement costs +14,294 +14,294 +— +— +— +— +— +AMT credit +— +— +— +— +— +(602 +) +602 +Other +14,501 +3,137 +11,364 +4,386 +6,978 +1,238 +5,740 +57,028 +24,333 +32,695 +8,970 +23,725 +4,051 +19,674 +Non-current: +Federal net operating loss +carryforwards +374 +(1,871 +) +2,245 +(1,870 +) +4,115 +4,115 +— +AMT credit +118 +— +118 +— +118 +118 +— +Federal benefit of foreign deferred +tax liabilities +8,549 +353 +8,196 +1,488 +6,708 +933 +5,775 +Federal benefit of state deferred +tax liabilities +4,692 +460 +4,232 +717 +3,515 +421 +3,094 +Embezzlement costs +— +— +— +(22,178 +) +22,178 +7,193 +14,985 +Other +7,109 +6,172 +937 +174 +763 +763 +— +20,842 +5,114 +15,728 +(21,669 +) +37,397 +13,543 +23,854 +Total deferred tax assets +77,870 +29,447 +48,423 +(12,699 +) +61,122 +17,594 +43,528 +Deferred tax liabilities: +Current: +Other +(8,161 +) +(1,848 +) +(6,313 +) +1,421 +(7,734 +) +(4,509 +) +(3,225 +) +Non-current: +Property and equipment basis +difference +(203,500 +) +(23,775 +) +(179,725 +) +(6,381 +) +(173,344 +) +(25,534 +) +(147,810 +) +Other +(5,301 +) +(110 +) +(5,191 +) +(663 +) +(4,528 +) +167 +(4,695 +) +(208,801 +) +(23,885 +) +(184,916 +) +(7,044 +) +(177,872 +) +(25,367 +) +(152,505 +) +Total deferred tax liabilities +(216,962 +) +(25,733 +) +(191,229 +) +(5,623 +) +(185,606 +) +(29,876 +) +(155,730 +) +Net deferred tax liability +$ +(139,092 +) +$ +3,714 +$ +(142,806 +) +$ +(18,322 +) +$ +(124,484 +) +$ +(12,282 +) +$ +(112,202 +) +Management deducted accumulated net embezzlement losses in the +Company’s 2005 tax returns, which corresponds with the +period in which the embezzlement was detected. +Other deferred tax assets consist primarily of various allowance +accounts and tax deferred expenses expected to generate future +tax benefit of approximately $22 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, +2006, Federal net operating loss carryforwards of approximately +$5 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: 2018 — $1 million and +2019 — $4 million. The alternative minimum tax +credit may be carried forward indefinitely. +F-23 +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $3.1 million in 2006, $2.7 million in +2005 and $2.2 million in 2004 for the Company’s +discretionary contributions to the plan. +15. +Business +Segments +The Company conducts its business through four distinct +operating segments: (1) contract drilling of oil and +natural gas wells, (2) pressure pumping services, +(3) drilling and completion fluids services to operators in +the oil and natural gas industry, and (4) the exploration, +development, acquisition and production of oil and natural gas. +Each of these segments represents a distinct type of business +based upon the type and nature of services and products offered. +These segments have separate management teams which report to +the Company’s chief executive officer and have distinct and +identifiable revenues and expenses. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2006, the Company +had 336 currently marketable land-based drilling rigs, of which +107 of the drilling rigs were based in the Permian Basin region, +50 in South Texas, 44 in the Ark-La-Tex region and Mississippi, +67 in the Mid-Continent region, 48 in the Rocky Mountain region +and 20 in Western Canada. +Pressure Pumping — The Company provides +pressure pumping services primarily in the Appalachian Basin. +Pressure pumping services consist primarily of well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Well stimulation involves processes inside a +well designed to enhance the flow of oil, natural gas, or other +desired substances from the well. Cementing is the process of +inserting material between the hole and the pipe to center and +stabilize the pipe in the hole. +Drilling and Completion Fluids — The Company +provides drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast region of Louisiana. Drilling and completion fluids +are used by oil and natural gas operators during the drilling +process to control pressure when drilling oil and natural gas +wells. +Oil and Natural Gas — The Company is engaged in +the development, exploration, acquisition and production of oil +and natural gas. +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2006 +2005 +2004 +Revenues: +Contract drilling(a) +$ +2,174,805 +$ +1,488,485 +$ +815,683 +Pressure pumping +145,671 +93,144 +66,654 +Drilling and completion fluids(b) +192,974 +122,309 +90,858 +Oil and natural gas +39,187 +39,616 +33,867 +Total segment revenues +2,552,637 +1,743,554 +1,007,062 +Elimination of intercompany +revenues(a)(b) +(6,051 +) +(3,099 +) +(6,293 +) +Total revenues +$ +2,546,586 +$ +1,740,455 +$ +1,000,769 +Income before income taxes: +Contract drilling +$ +991,449 +$ +572,562 +$ +146,626 +Pressure pumping +44,835 +21,664 +16,747 +Drilling and completion fluids +28,759 +12,201 +4,202 +Oil and natural gas +8,660 +13,405 +10,764 +1,073,703 +619,832 +178,339 +F-24 +Years Ended December 31, +2006 +2005 +2004 +Corporate and other +(22,054 +) +(14,245 +) +(11,264 +) +Other operating expenses(c) +(9,404 +) +(4,248 +) +514 +Embezzlement costs, net of +recoveries(d) +(3,081 +) +(20,043 +) +(19,122 +) +Interest income +5,925 +3,551 +1,140 +Interest expense +(1,602 +) +(516 +) +(695 +) +Other +347 +428 +235 +Income before income taxes +$ +1,043,834 +$ +584,759 +$ +149,147 +Identifiable assets: +Contract drilling +$ +1,849,923 +$ +1,421,779 +$ +961,873 +Pressure pumping +111,787 +72,536 +49,145 +Drilling and completion fluids +106,032 +90,904 +62,970 +Oil and natural gas +65,443 +60,785 +62,984 +2,133,185 +1,646,004 +1,136,972 +Corporate and other(e) +59,318 +149,777 +119,813 +Total assets +$ +2,192,503 +$ +1,795,781 +$ +1,256,785 +Depreciation, depletion and +impairment: +Contract drilling +$ +168,607 +$ +131,740 +$ +101,779 +Pressure pumping +9,896 +7,094 +5,112 +Drilling and completion fluids +2,706 +2,368 +2,156 +Oil and natural gas +14,368 +14,456 +13,309 +195,577 +155,658 +122,356 +Corporate and other +793 +735 +444 +Total depreciation, depletion and +impairment +$ +196,370 +$ +156,393 +$ +122,800 +Capital expenditures: +Contract drilling +$ +531,087 +$ +329,073 +$ +140,945 +Pressure pumping +41,262 +25,508 +17,705 +Drilling and completion fluids +4,222 +3,042 +1,488 +Oil and natural gas +21,198 +17,163 +14,451 +Corporate and other +150 +5,308 +— +Total capital expenditures +$ +597,919 +$ +380,094 +$ +174,589 +(a) +Includes contract drilling intercompany revenues of +approximately $5.4 million, $2.8 million and +$6.0 million for the years ended December 31, 2006, +2005 and 2004, respectively. +(b) +Includes drilling and completion fluids intercompany revenues of +approximately $616,000, $298,000 and $301,000 for the years +ended December 31, 2006, 2005 and 2004, respectively. +(c) +Other operating expenses relate to decisions of the executive +management group regarding corporate strategy, credit risk, loss +contingencies and restructuring activities. Due to the +non-operating nature of these decisions, the related charges +have been separately presented and excluded from the results of +specific segments. These charges are primarily related to the +contract drilling segment. +(d) +The Company’s former CFO has pleaded guilty to criminal +charges and has been sentenced and is serving a term of +imprisonment arising out of his embezzlement of funds totaling +approximately $77.5 million from the Company over a period +of more than five years, ending November 3, 2005. +Embezzlement costs, net of recoveries include embezzled funds +and other costs incurred as a result of the embezzlement. In +2006, the Company recovered $2.0 million from its insurance +carrier related to the embezzlement loss. +F-25 +(e) +Corporate assets primarily include cash on hand managed by the +parent corporation and certain deferred Federal income tax +assets. +16. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2006 +Operating revenues +$ +597,733 +$ +636,813 +$ +673,658 +$ +638,382 +Operating income +245,599 +268,913 +281,905 +242,747 +Net income +159,256 +171,690 +185,990 +156,318 +Net income per common share: +Basic +$ +0.93 +$ +1.02 +$ +1.14 +$ +0.99 +Diluted +$ +0.91 +$ +1.00 +$ +1.12 +$ +0.97 +2005 +Operating revenues +$ +350,593 +$ +389,922 +$ +468,739 +$ +531,201 +Operating income +91,833 +116,651 +167,446 +205,366 +Net income +58,220 +74,026 +106,305 +134,189 +Net income per common share: +Basic +$ +0.34 +$ +0.44 +$ +0.62 +$ +0.78 +Diluted +$ +0.34 +$ +0.43 +$ +0.61 +$ +0.77 +17. +Concentrations +of Credit Risk +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes that it places its demand deposits and +temporary cash investments with high credit quality financial +institutions. At December 31, 2006 and 2005, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2006 +2005 +Deposits in FDIC and SIPC-insured +institutions under $100,000 +$ +684 +$ +1,066 +Deposits in FDIC and SIPC-insured +institutions over $100,000 +21,859 +153,261 +Deposits in Foreign Banks +3,754 +2,513 +26,297 +156,840 +Less outstanding checks and other +reconciling items +(12,912 +) +(20,442 +) +Cash and cash equivalents +$ +13,385 +$ +136,398 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides drilling services. As +is general industry practice, the Company typically does not +require customers to provide collateral. No significant losses +from individual customers were experienced during the years +ended December 31, 2006, 2005, or 2004. The Company +recognized bad debt expense for 2006, 2005 and 2004 of +$5.4 million, $1.2 million and $897,000, respectively. +The carrying values of cash and cash equivalents, marketable +securities, trade receivables and borrowings outstanding under +the Company’s line of credit approximate fair value due to +the short-term maturity of these items. +18. +Related +Party Transactions +Joint Operation of Oil and Natural Gas +Properties — The Company operates certain oil and +natural gas properties in which certain of its affiliated +persons have participated, either individually or through +entities they control. These participations have typically been +through working interests in prospects or properties originated +or acquired by Patterson Petroleum LP, LLLP, a wholly owned +subsidiary of Patterson-UTI. At December 31, 2006, +F-26 +affiliated persons were working interest owners in 281 of 330 +total wells operated by Patterson-UTI. Sales of working +interests to affiliated parties were made by Patterson-UTI at +its cost, comprised of Patterson-UTI’s costs of acquiring +and preparing the working interests for sale plus a promote fee +in some cases. These costs were paid by the working interest +owners on a pro rata basis based upon their working interest +ownership percentage. The price at which working interests were +sold to affiliated persons was the same price at which working +interests were sold to unaffiliated persons except that in some +cases the affiliated persons also paid a promote fee. The +affiliated persons earned oil and natural gas production revenue +(net of royalty) of $15.8 million, $15.5 million and +$13.8 million from these properties in 2006, 2005 and 2004, +respectively. These persons or entities in turn paid for joint +operating costs (including drilling and other development +expenses) of $14.1 million, $9.5 million and +$7.5 million incurred in 2006, 2005 and 2004, respectively. +These activities resulted in a payable to the affiliated persons +of approximately $1.5 million and $1.5 million and a +receivable from the affiliated persons of approximately +$1.6 million and $1.2 million at December 31, +2006 and 2005, respectively. +F-27 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — +VALUATION AND QUALIFYING ACCOUNTS +Charged to +Costs and +Description +Beginning Balance +Expenses(1) +Deductions(2) +Ending Balance +(In thousands) +Year Ended December 31, +2006 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +2,199 +$ +5,400 +$ +115 +$ +7,484 +Year Ended December 31, +2005 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +1,909 +$ +1,231 +$ +941 +$ +2,199 +Year Ended December 31, +2004 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +2,133 +$ +897 +$ +1,121 +$ +1,909 +(1) +Net of recoveries. +(2) +Uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Cloyce +A. Talbott +Cloyce A. Talbott +President and Chief Executive Officer +Date: February 26, 2007 +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 +February 26, 2007. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +(Principal Executive Officer) +President, Chief Executive Officer +and Director +/s/ John +E. +Vollmer III +John +E. Vollmer III +(Principal Financial and Accounting Officer) +Senior Vice President — +Corporate Development, +Chief Financial Officer and Treasurer +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Robert +C. Gist +Robert +C. Gist +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +Nadine +C. Smith +Director +EXHIBIT INDEX +3 +.1 +Restated Certificate of +Incorporation, as amended (filed August 9, 2004 as +Exhibit 3.1 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate +of Incorporation, as amended (filed August 9, 2004 as +Exhibit 3.2 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Amended and Restated Bylaws (filed +March 19, 2002 as Exhibit 3.2 to the Company’s +Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated +January 2, 1997, between Patterson Energy, Inc. and +Continental Stock Transfer & Trust Company (filed +January 14, 1997 as Exhibit 2 to the Company’s +Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement +dated as of October 23, 2001 (filed October 31, 2001 +as Exhibit 3.4 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of +Incorporation, as amended (See Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with +Bear, Stearns and Co. Inc., dated March 25, 1994, as +assigned by REMY Capital Partners III, L.P.(filed +March 19, 2002 as Exhibit 4.3 to the Company’s +Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, +see Exhibits 4.1, 4.2 and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 +Stock Incentive Plan, as amended (filed March 13, 1998 as +Exhibit 10.1 to the Company’s Registration Statement +on +Form S-8 +(File +No. 333-47917) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. +Non-Employee Directors’ Stock Option Plan, as amended +(filed November 4, 1997 as Exhibit 10.1 to the +Company’s Registration Statement on +Form S-8 +(File +No. 333-39471) +and incorporated herein by reference).* +10 +.4 +Amended and Restated Patterson-UTI +Energy, Inc. 2001 Long-Term Incentive Plan (filed +November 27, 2002 as Exhibit 4.4 to Post Effective +Amendment No. 1 to the Company’s Registration +Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Amended +and Restated 1997 Long-Term Incentive Plan (filed July 28, +2003 as Exhibit 4.7 to the Company’s Quarterly Report +on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.6 +Amendment to the Patterson-UTI +Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan +(filed August 9, 2004 as Exhibit 10.7 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.7 +Amended and Restated Patterson-UTI +Energy, Inc. Non-Employee Director Stock Option Plan(filed +July 28, 2003 as Exhibit 4.8 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.8 +Amended and Restated Patterson-UTI +Energy, Inc. 1996 Employee Stock Option Plan (filed +July 25, 2001 as Exhibit 4.4 to Post-Effective +Amendment No. 1 to the Company’s Registration +Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.9 +Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan, including Form of Executive Officer +Restricted Stock Award Agreement, Form of Executive Officer +Stock Option Agreement, Form of Non-Employee Director Restricted +Stock Award Agreement and Form of Non-Employee Director Stock +Option Agreement (filed June 15, 2005 as Exhibit 10.1 +to the Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.10 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Mark S. Siegel (filed August 9, 2004 as Exhibit 10.1 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.11 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Cloyce A. Talbott (filed August 9, 2004 as +Exhibit 10.2 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.12 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +A. Glenn Patterson (filed August 9, 2004 as +Exhibit 10.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.13 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +Kenneth N. Berns (filed August 9, 2004 as Exhibit 10.4 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Restricted Stock Award Agreement +dated April 28, 2004 between Patterson-UTI Energy, Inc. and +John E. Vollmer III (filed August 9, 2004 as +Exhibit 10.6 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.15 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed +on February 4, 2004 as Exhibit 10.2 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.16 +Employment Agreement, effective as +of May 3, 2006 between Patterson-UTI Energy, Inc. and A. +Glenn Patterson (filed on May 5, 2006 as Exhibit 10.1 +to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended March 31, 206 and +incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott +(filed on February 4, 2004 as Exhibit 10.4 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and Kenneth N. Berns +(filed on February 4, 2004 as Exhibit 10.5 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.19 +Patterson-UTI Energy, Inc. Change +in Control Agreement, effective as of January 29, 2004, by +and between Patterson-UTI Energy, Inc. and John E. +Vollmer III (filed on February 4, 2004 as +Exhibit 10.7 to the Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.20 +Form of Letter Agreement regarding +termination, effective as of January 29, 2004, entered into +by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, +Kenneth N. Berns and John E. Vollmer III (filed 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).* +10 +.21 +Form of Indemnification Agreement +entered into by Patterson-UTI Energy, Inc. with each of Mark S. +Siegel, Cloyce A. Talbott, A. Glenn Patterson, Kenneth N. Berns, +Robert C. Gist, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, +Nadine C. Smith and John E. Vollmer III (filed +April 28, 2004 as Exhibit 10.11 to the Company’s +Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.22 +Credit Agreement dated as of +December 17, 2004 among Patterson-UTI Energy, Inc., as the +Borrower, Bank of America, N.A., as administrative agent, L/C +Issuer and a Lender and the other lenders and agents party +thereto (filed on December 23, 2004 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.23 +Commitment Increase and Joinder +Agreement, dates as of August 2, 2006, by and among +Patterson-UTI Energy, Inc., the guarantors party thereto, the +lenders party thereto, and Bank of America, N.A. as +Administrative Agent, L/C Issuer and Lender (filed +August 21, 2006 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K +and incorporated herein by reference). +10 +.24 +Letter Agreement dated +February 6, 2006 between Patterson-UTI Energy, Inc. and +John E. Vollmer III (filed May 1, 2006 as +Exhibit 10.25 to the Company’s Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of +Business Conduct and Ethics for Senior Financial Executives +(filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered +Public Accounting Firm. +31 +.1 +Certification of Chief Executive +Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial +Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive +Officer and Chief Financial Officer pursuant to 18 USC +Section 1350, as adopted pursuant to Section 906 of +the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/filing_metadata.csv b/raw/filings/0000889900/2006/0000950134-07-004227/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..2aaa5c117a5c23c14b1c5d15e6c10476ecd6cd7b --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2007-02-27,2006-12-31,2007-02-27T17:28:13.000Z,0000950134-07-004227,d43932e10vk.htm,FORM 10-K,1214014,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013407004227/d43932e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095013407004227/,2006,2006,1 diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/item1.txt b/raw/filings/0000889900/2006/0000950134-07-004227/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..d0c6296ba17fe3fb8110d041f41c8d493a8d46c6 --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/item1.txt @@ -0,0 +1,700 @@ +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file 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 operator 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, +• +Arkansas, +• +Louisiana, +• +Mississippi, +• +Colorado, +• +Utah, +• +Wyoming, +• +Montana, +• +North Dakota, +• +South Dakota, and +• +Western Canada (Alberta, British Columbia and Saskatchewan). +As of December 31, 2006, we had a drilling fleet that +consisted of 336 currently marketable land-based 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. A drilling rig is considered +currently marketable at a point in time if it is operating or +can be made ready to operate without significant capital +expenditures. We also have a substantial inventory of drilling +rig components and equipment which may be used in the activation +of additional drilling rigs or as replacement parts for +marketable rigs. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast +1 +region of Louisiana. Drilling and completion fluids are used by +oil and natural gas operators during the drilling process to +control pressure when drilling oil and natural gas wells. We are +also engaged in the development, exploration, acquisition and +production of oil and natural gas. Our oil and natural gas +operations are focused primarily in producing regions of West +and South Texas, Southeastern New Mexico, Utah and Mississippi. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas development, exploration, acquisition and +production. +All of our industry segments had operating profits in 2006, 2005 +and 2004. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for +financial information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2006, we had 336 currently marketable +land-based drilling rigs which were based in the following +regions: +• +107 in the Permian Basin region (West Texas and Southeastern New +Mexico), +• +50 in South Texas, +• +44 in the Ark-La-Tex region and Mississippi, +• +67 in the Mid-Continent region (Oklahoma and North Central +Texas), +• +48 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana, North Dakota and South Dakota), and +• +20 in Western Canada (Alberta, British Columbia and +Saskatchewan). +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Fifty-six of these drilling rigs are SCR electric rigs and 280 +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. We also have a substantial inventory of drilling rig +components and equipment which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with: +• +engines, +• +drawworks or hoists, +• +derricks or masts, +• +pumps to circulate the drilling fluid, +• +blowout preventers, +• +drill string (pipe), and +• +other related equipment. +2 +Over time, components on a drilling rig are replaced or rebuilt. +We spend significant funds each year on an ongoing program to +modify and upgrade our drilling rigs to ensure that our drilling +equipment is well maintained and competitive. We have spent +$1 billion during the last three years on capital +improvements to modify and upgrade our drilling rigs. During +fiscal years 2006, 2005 and 2004, we spent approximately +$531 million, $329 million and $141 million, +respectively, on these capital improvements. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. We use our rigs for developmental and +exploratory drilling, and they are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of: +• +drill pipe, +• +bits, +• +replacement parts and other related rig equipment, +• +fuel, and +• +qualified personnel, +some of which have been in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Typically, the contracts are short-term to +drill a single well or a series of wells. 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 and 2006. These long-term +contracts provide for the use of drilling rigs for fixed periods +of time during which multiple wells are drilled. During 2006, +our average number of days to drill a well was approximately +21 days. We may continue to enter into long-term contracts +when considered beneficial 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. +Most drilling contracts are subject to termination by the +customer on short notice. We generally indemnify our customers +against claims by our employees and claims that might arise from +surface pollution caused by spills of fuel, lubricants and other +solvents within our control. The customers generally indemnify +us against claims that might arise from other surface and +subsurface pollution, except claims that might arise from our +gross negligence. +The contracts provide for payment on a daywork, footage, or +turnkey basis, or a combination thereof. In each case, we +provide the rig and crews. Our bid for each contract depends +upon: +• +location, depth and anticipated complexity of the well, +• +on-site +drilling conditions, +• +equipment to be used, +• +estimated risks involved, +• +estimated duration of the job, +• +availability of drilling rigs, and +• +other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We sometimes receive a +lower rate when the drilling rig is moving, or when drilling +operations are +3 +interrupted or restricted by adverse weather conditions or other +conditions beyond our control. Daywork contracts typically +provide separately for mobilization of the drilling rig. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor assumes certain risks +associated with loss of the well from fire, blowouts and other +risks. 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 specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also assume +certain risks associated with drilling the well such as fires, +blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed scope of the work has +been completed, which requires us to make larger up-front +working capital commitments prior to receiving payments under a +turnkey drilling contract. Under a turnkey contract, we have the +opportunity to improve our profits if the drilling process goes +as expected and there are no complications or time delays. +However, given the increased exposure we have under a turnkey +contract, profits can be significantly reduced and losses can be +incurred if complications or delays occur during the drilling +process. Turnkey contracts generally involve the highest degree +of risk among the three different types of drilling contracts: +daywork, footage and turnkey. 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. +Revenues by Contract Type — Information +regarding our revenues by contract type for the last three years +follows: +Year Ended December 31, +Type of Revenues +2006 +2005 +2004 +Daywork +100 +% +98 +% +88 +% +Footage +0 +1 +6 +Turnkey +0 +1 +6 +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2006 +2005 +2004 +Average rigs operating(1) +296 +276 +211 +Number of rigs operated +331 +307 +259 +Number of wells drilled +5,050 +4,594 +3,534 +Number of operating days +108,221 +100,591 +77,355 +(1) +A rig is operating when it is drilling, being moved, assembled, +dismantled or otherwise earning revenue under contract. +4 +Drilling Rigs and Related Equipment — Certain +drilling rig information with respect to rigs that were +currently marketable as of December 31, 2006 follows: +Depth Rating (Ft.) +Mechanical +Electric +Total +5,000 to 9,999 +33 +— +33 +10,000 to 11,999 +49 +3 +52 +12,000 to 13,999 +60 +5 +65 +14,000 to 15,999 +120 +21 +141 +16,000 to 30,000 +18 +27 +45 +Totals +280 +56 +336 +At December 31, 2006, we owned and operated 336 trucks and +439 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and Western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the well bore. Generally, Appalachian Basin wells require +cementing services before production commences. The cementing +process inserts material between the wall of the well bore and +the casing to center and stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2006 follows: +• +36 cement pumper trucks, +• +35 fracturing pumper trucks, +• +37 nitrogen pumper trucks, +• +20 blender trucks, +• +7 bulk acid trucks, +• +44 bulk cement trucks, +• +14 bulk nitrogen trucks, +• +3 bulk nitrogen trailers, +• +40 bulk sand trucks, +• +21 connection trucks, +• +3 acid pumper trucks, and +• +10 sand pneumatic trucks. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +Southeastern New Mexico, Oklahoma and the Gulf Coast region of +Louisiana. We serve our offshore customers through six +stockpoint facilities located along the Gulf of +5 +Mexico in Texas and Louisiana and our land-based customers +through eleven stockpoint facilities in Texas, Louisiana, +Oklahoma and New Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to ensure that the products and systems are applied +effectively to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +Raw Materials — Our drilling and completion +fluids 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 — We own and operate a +barite grinding facility with two barite grinding mills in +Houma, Louisiana. This facility allows us to grind raw barite +into the powder additive used in drilling fluids. +Other Equipment — We operate 20 trucks and 83 +trailers and lease another 33 trucks which are used to transport +drilling and completion fluids and related equipment. +Oil and +Natural Gas Operations +General — We are engaged in the development, +exploration, acquisition and production of oil and natural gas. +Our oil and natural gas business operates primarily in producing +regions of West and South Texas, Southeastern New Mexico, Utah +and Mississippi. We significantly expanded our oil and natural +gas operations in 2004 through our acquisition of TMBR/Sharp +Drilling, Inc. (“TMBR”). The oil and natural gas +assets acquired in the acquisition of TMBR included both proved +reserves and undeveloped properties. +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 2006, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping Businesses — +Our land drilling and pressure pumping businesses are highly +competitive. At times, available land drilling rigs and pressure +pumping equipment exceed the demand for such equipment. The +equipment can also be moved from one market to another in +response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +6 +Oil and Natural Gas Business — There is +substantial competition for the acquisition of oil and natural +gas leases suitable for development and exploration and for +experienced personnel. Our competitors in this business include: +• +major integrated oil and natural gas operators, +• +independent oil and natural gas operators, and +• +drilling and production purchase programs. +Our ability to increase our oil and natural gas reserves in the +future is directly dependent upon our ability to select, acquire +and develop suitable prospects. Many of our competitors have +facilities and financial and human resources greater than ours. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. Several state and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We use operating and disposal practices that are standard in the +industry. However, hydrocarbons and other materials may have +been disposed of or released in or under properties currently or +formerly owned or operated by us or our predecessors. In +addition, some of these properties have been operated by third +parties over whom we have no control of their treatment of +hydrocarbon and other materials or the manner in which they may +have disposed of or released such materials. +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +7 +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a “major source.” As a +consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting +process may require capital expenditures in order to comply with +permit limits. +Risks and +Insurance +Our operations are subject to the many hazards inherent in the +drilling business, including: +• +accidents at the work location, +• +blow-outs, +• +cratering, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +8 +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for public liability +and property damage to others with respect to our operations. +However, such insurance may not be sufficient to protect us +against liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance coverage for major physical damage to +our drilling rigs. However, we do not carry insurance against +loss of earnings resulting from such damage. In view of the +difficulties that may be encountered in renewing such insurance +at reasonable rates, no assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications may not be supported by +adequate insurance maintained by the customer. +Employees +We had approximately 9,000 full-time employees at +December 31, 2006. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our pressure pumping division in Appalachia +and our drilling operations in Canada are subject to slow +periods of activity during the Spring thaw. In addition, our +drilling operations in Canada are subject to slow periods of +activity during the Fall. +Raw +Materials and Subcontractors +We use many suppliers of raw materials and services. These +materials and services have historically been available, +although there is no assurance that such materials and services +will continue to be available on favorable terms or at all. We +also utilize numerous independent subcontractors from various +trades. +9 \ No newline at end of file diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/item13.txt b/raw/filings/0000889900/2006/0000950134-07-004227/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..a7286a7e2510bb2591e1590dae3153b21f546be9 --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/item13.txt @@ -0,0 +1,6 @@ +Item 13. +Certain +Relationships, Related Transactions and Director +Independence. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/item9a.txt b/raw/filings/0000889900/2006/0000950134-07-004227/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..7f94ed3f74c6bcf8d28f4c76311fa23c0e72977e --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/item9a.txt @@ -0,0 +1,139 @@ +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2006, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time +32 +periods specified in SEC rules and forms and is accumulated and +reported to our management, including our CEO and CFO, as +appropriate to allow timely decisions regarding required +disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2006, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2006. +Our assessment of the effectiveness of our internal control over +financial reporting as of December 31, 2006 has been +audited by PricewaterhouseCoopers LLP, an independent registered +public accounting firm, as stated in their report which appears +under Item 8 of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +As of December 31, 2005, in our assessment of the +effectiveness of our internal control over financial reporting, +we identified material weaknesses in our internal control over +financial reporting relating to: +1. Control environment. We 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, +financial statements and documents together with forged approval +signatures. This control environment material weakness +contributed to the embezzlement by our former Chief Financial +Officer, Jonathan D. Nelson, of our funds for his own benefit, +and in turn resulted in the restatement of our consolidated +financial statements for the years ended December 31, 2004, +2003 and 2002, each of the quarters of 2004 and 2003, and the +first three quarters of 2005. +2. Controls over property and +equipment. We did not maintain effective controls +over the completeness and accuracy of our accounting for +property and equipment including (i) the timely and +accurate depreciation of all property and equipment, +(ii) the identification 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 reflected in our accounting records. +This control deficiency resulted in certain inaccuracies in our +accounting for property and equipment and in the restatement of +our consolidated financial statements for the years ended +December 31, 2004, 2003 and 2002; each of the quarters of +2004 and 2003; and the first three quarters of 2005. +These material weaknesses are discussed in greater detail in our +Annual Report on +Form 10-K +for the year ended December 31, 2005. +During the fourth quarter of 2006, we completed the +implementation of the following remediation steps to address the +material weakness in our control environment: +• +employees provide formal certifications of information contained +in SEC filings related to their areas of responsibility; +• +senior employees and accounting staff submit annual written +questionnaires with respect to awareness as to questionable +business practices; +• +educational and training programs covering ethics, compliance, +financial reporting, good business practices and fraud awareness +have been provided to employees; +• +additional guidelines were provided to senior management with +respect to their responsibilities for SEC filings, financial +reports, budgets and maintenance of controls over assets and +expenditures; and, +• +annual reporting to the audit committee with respect to these +processes and procedures was added. +33 +Additionally, certain structural changes and processes and +procedures were instituted to increase communications between +the financial reporting and accounting functions and operations +and between financial reporting and accounting functions and +senior management. The internal audit reporting structure was +also revised to provide for enhanced reporting to the audit +committee. +During the fourth quarter of 2006, we completed the +implementation of the following remediation steps to address the +material weakness in our controls over property and equipment: +• +increased coordination between accounting staff and operations +to more promptly identify the impairment or retirement of +drilling equipment undergoing refurbishment or repair; +• +instituted quarterly physical inventories of our drill pipe and +drill collars with comparison of the results of those +inventories to our property records; +• +instituted an annual physical inventory of significant drilling +equipment with comparison of the results of that inventory to +our property records; and, +• +improved procedures to identify property placed in service and +to begin depreciation of those assets when placed in service. +The changes described above are changes in our internal control +over financial reporting during the most recently completed +fiscal quarter that have materially affected, or are reasonably +likely to materially affect, our internal control over financial +reporting. \ No newline at end of file diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/rp_note.txt b/raw/filings/0000889900/2006/0000950134-07-004227/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2006/0000950134-07-004227/rpt_disclosure.txt b/raw/filings/0000889900/2006/0000950134-07-004227/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..62c18181dddc029d81f5591ac1cdb7e14e357689 --- /dev/null +++ b/raw/filings/0000889900/2006/0000950134-07-004227/rpt_disclosure.txt @@ -0,0 +1,27 @@ +related person transaction are considered, including whether +such transaction is in, or not inconsistent with, the best +interest of Patterson-UTI and whether, in appropriate cases, +such transaction is on commercial terms at least as favorable to +Patterson-UTI as would otherwise be available to or from an +unrelated third party or to Patterson-UTI’s employees +generally. Related person transactions generally include +transactions in an amount that exceeds $50,000 between +Patterson-UTI or any of its subsidiaries and an executive +officer, a director (or nominee to become director), an +immediate family member of any of the foregoing or any entity in +which any of the foregoing has a 10% or greater beneficial +ownership interest or in which they are an executive officer, +general partner, principal or engaged in a similar position. +Certain related person transactions have been pre-approved under +the terms of the policy, including, subject to certain +exceptions and limitations, the personal use of the +Patterson-UTI airplane by executive officers, co-investment in +oil and gas properties by Mr. Talbott and other persons +related to him, and the sale to or purchase from Patterson-UTI +of goods and services by entities related to directors in the +ordinary course of business that are immaterial to Patterson-UTI +and with respect to which the director has no direct economic +interest or decision making authority. +27 +Table of Contents +SECURITY \ No newline at end of file diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/filing.txt b/raw/filings/0000889900/2007/0000950134-08-003007/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..a9904b13c1ab8cb9a225180b4d849f52ab823663 --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/filing.txt @@ -0,0 +1,7381 @@ +10-K +1 +d54088e10vk.htm +FORM 10-K +e10vk +Table of Contents +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. +20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2007 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, +Inc. +(Exact name of registrant as +specified in its charter) +Delaware +(State or other jurisdiction +of +incorporation or organization) +75-2504748 +(I.R.S. Employer +Identification No.) +4510 Lamesa Highway, Snyder, Texas +(Address of principal +executive offices) +79549 +(Zip +Code) +Registrant’s telephone number, including area code: +(325) 574-6300 +Securities Registered Pursuant to 12(b) of the Act: +None +Securities Registered Pursuant to 12(g) of the Act: +(Title of class) +Common Stock, $.01 Par Value +Indicate by check mark if the registrant is a well-known +seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes þ or +No o +Indicate by check mark if the registrant is not required to file +reports pursuant to Section 13 or Section 15(d) of the +Act. Yes o or +No þ +Indicate by check mark whether the registrant (1) has filed +all reports required to be filed by Section 13 or 15(d) of +the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant +was required to file such reports), and (2) has been +subject to such filing requirements for the past +90 days. Yes þ No o +Indicate by check mark if disclosure of delinquent filers +pursuant to Item 405 of +Regulation S-K +is not contained herein, and will not be contained, to the best +of the registrant’s knowledge, in definitive proxy or +information statements incorporated by reference in +Part III of this +Form 10-K +or any amendment to this +Form 10-K. þ +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, a non-accelerated +filer, or a smaller reporting company. See the definitions of +“large accelerated filer,” “accelerated +filer” and “smaller reporting company” in Rule +12b-2 of the Exchange Act. (Check one): +Large accelerated +filer þ +Accelerated +filer o +Non-accelerated +filer o +Smaller reporting +company o +Indicate by check mark whether the registrant is a shell company +(as defined in +Rule 12b-2 +of the +Act). Yes o No þ +The aggregate market value of the voting and non-voting common +equity held by non-affiliates of the registrant as of +June 29, 2007, the last business day of the +registrant’s most recently completed second fiscal quarter, +was $4,052,686,260, calculated by reference to the closing price +of $26.21 for the common stock on the Nasdaq National Market on +that date. +As of February 15, 2008, the registrant had outstanding +154,027,206 shares of common stock, $.01 par value, +its only class of common stock. +Documents incorporated by reference: +Definitive Proxy Statement for the 2008 Annual Meeting of +Stockholders (Part III). +Table of Contents +FORWARD-LOOKING +STATEMENTS +Certain statements made in this Annual Report on +Form 10-K +and in other public filings and press releases by the Company +contain “forward-looking” information (as defined in +the Private Securities Litigation Reform Act of 1995) that +involves risk and uncertainty. These forward-looking statements +may include, but are not limited to, references to liquidity, +financing of operations, impact of inflation, future capital +expenditures, oil and natural gas prices and demand for drilling +rigs. Our forward-looking statements can be identified by the +fact that they do not relate strictly to historic or current +facts and often use words such as “believes,” +“budgeted,” “expects,” “project,” +“will,” “could,” “may,” +“plans,” “intends,” “strategy,” or +“anticipates,” and other words and expressions of +similar meaning. Although we believe that the expectations +reflected in such forward-looking statements are reasonable, we +can give no assurance that such expectation will prove to have +been correct. Forward-looking statements may be made by +management orally or in writing, including, but not limited to, +Management’s Discussion and Analysis of Financial Condition +and Results of Operations included in this Annual Report on +Form 10-K +and other sections of our filings with the Securities and +Exchange Commission under the Securities Exchange Act of 1934 +and the Securities Act of 1933. +Forward-looking statements are not guarantees of future +performance and a variety of factors could cause actual results +to differ materially from the anticipated or expected results +expressed in or suggested by these forward-looking statements. +Factors that might cause or contribute to such differences +include, but are not limited to, declines in oil and natural gas +prices that could adversely affect demand for the Company’s +services and their associated effect on day rates, rig +utilization and planned capital expenditures, excess +availability of land drilling rigs, including as a result of the +reactivation or construction of new land drilling rigs, adverse +industry conditions, difficulty in integrating acquisitions, +demand for oil and natural gas, shortages of rig equipment and +ability to retain management and field personnel. Refer to +“Risk Factors” contained in Part 1 of this Annual +Report on +Form 10-K +for a more complete discussion of these and other factors that +might affect our performance and financial results. These +forward-looking statements are intended to relay the +Company’s expectations about the future, and speak only as +of the date they are made. We undertake no obligation to +publicly update or revise any forward-looking statement, whether +as a result of new information, future events or otherwise. +PART I +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the +United States Securities and Exchange Commission +(“SEC”). You may read and copy any materials we file +with the SEC at the SEC’s Public Reference Room at +100 F Street, NE, Washington, DC 20549. You may obtain +information on the operation of the Public Reference Room by +calling the SEC at +1-800-SEC-0330. +Overview +Based on publicly available information, we believe we are the +second largest operator 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, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, South Dakota, Pennsylvania and western Canada (Alberta, +British Columbia and Saskatchewan). +As of December 31, 2007, we had a drilling fleet that +consisted of 350 currently marketable land-based 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. A drilling rig is considered +currently marketable at a point in time if it is +1 +Table of Contents +operating or can be made ready to operate without significant +capital expenditures. We also have a substantial inventory of +drilling rig components and equipment. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast region of Louisiana. Drilling and completion fluids +are used by oil and natural gas operators during the drilling +process to control pressure when drilling oil and natural gas +wells. We own and invest in oil and natural gas assets as a +working interest owner. Our oil and natural gas interests are +located primarily in producing regions of West and South Texas, +Southeastern New Mexico, Utah and Mississippi. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2007, 2006 +and 2005. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2007, we had 350 currently marketable +land-based drilling rigs which were based in the following +regions: +• +107 in the Permian Basin region (West Texas and Southeastern New +Mexico), +• +51 in South Texas, +• +42 in the Ark-La-Tex region and Mississippi, +• +75 in the Mid-Continent region (Oklahoma and North Central +Texas), +• +52 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana, North Dakota and South Dakota), +• +3 in the Appalachian Basin, and +• +20 in Western Canada (Alberta, British Columbia and +Saskatchewan). +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Sixty-nine of these drilling rigs are electric rigs and 281 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. We also have a substantial inventory of drilling rig +components and equipment which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year on an ongoing program to modify and +upgrade our drilling rigs to ensure that our drilling equipment +is competitive. We have spent $1.4 billion during the last +three years on capital expenditures to modify, upgrade and +maintain our drilling fleet. During fiscal years 2007, 2006 and +2005, we spent approximately $540 million, +$531 million and $329 million, respectively, on these +capital expenditures. +2 +Table of Contents +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. Our rigs are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Typically, the contracts are short-term to +drill a single well or a series of wells. 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 +long-term contracts in 2005 and 2006 and, to a lesser extent, in +2007. These long-term contracts provide for the use of drilling +rigs for fixed periods of time during which multiple wells are +drilled. During 2007, our average number of days to drill a well +(which includes moving to the drill site, rigging up and rigging +down) was approximately 21 days. We may continue to enter +into long-term contracts when considered beneficial 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. +Most drilling contracts are subject to termination by the +customer on short notice. We generally indemnify our customers +against claims by our employees and claims that might arise from +surface pollution caused by spills of fuel, lubricants and other +solvents within our control. The customers generally indemnify +us against claims that might arise from other surface and +subsurface pollution, except claims that might arise from our +gross negligence. Each drilling contract will contain the actual +terms setting forth our rights and obligations and those of the +particular customer. +The contracts provide for payment on a daywork, footage, or +turnkey basis, or a combination thereof. In each case, we +provide the rig and crews. Our bid for each contract depends +upon location, depth and anticipated complexity of the well, +on-site +drilling conditions, equipment to be used, estimated risks +involved, estimated duration of the job, availability of +drilling rigs and other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving, or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor assumes certain risks +associated with loss of the well from fire, blowouts and other +risks. Due to market conditions, we have entered into very few +footage contracts in recent years. +Turnkey +Contracts +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also assume +certain risks associated with drilling the well such as fires, +blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed scope of the work has +been +3 +Table of Contents +completed, which requires us to make larger up-front working +capital commitments prior to receiving payments under a turnkey +drilling contract. Under a turnkey contract, we have the +opportunity to improve our profits if the drilling process goes +as expected and there are no complications or time delays. +However, given the increased exposure we have under a turnkey +contract, profits can be significantly reduced and losses can be +incurred if complications or delays occur during the drilling +process. Turnkey contracts generally involve the highest degree +of risk among the three different types of drilling contracts: +daywork, footage and turnkey. Due to market conditions, we have +entered into very few turnkey contracts in recent years. +Revenues by Contract Type — Information +regarding our revenues by contract type for the last three years +follows: +Year Ended December 31, +Type of Revenues +2007 +2006 +2005 +Daywork +100 +% +100 +% +98 +% +Footage +0 +0 +1 +Turnkey +0 +0 +1 +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2007 +2006 +2005 +Average rigs operating(1) +244 +296 +276 +Number of rigs operated +338 +331 +307 +Number of wells drilled +4,237 +5,050 +4,594 +Number of operating days +89,095 +108,221 +100,591 +(1) +A rig is operating when it is drilling, being moved, assembled, +dismantled or otherwise earning revenue under contract. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to rigs that were +currently marketable as of December 31, 2007 to be as +follows: +Depth Rating (Ft.) +Mechanical +Electric +Total +5,000 to 7,999 +4 +— +4 +8,000 to 11,999 +74 +2 +76 +12,000 to 15,999 +186 +33 +219 +16,000 to 30,000 +17 +34 +51 +Totals +281 +69 +350 +At December 31, 2007, we owned and operated 324 trucks and +441 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and Western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the +4 +Table of Contents +well bore. Generally, Appalachian Basin wells require cementing +services before production commences. The cementing process +inserts material between the wall of the well bore and the +casing to center and stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2007 follows: +• +34 cement pumper trucks, +• +57 fracturing pumper trucks, +• +47 nitrogen pumper trucks, +• +26 blender trucks, +• +24 acid trucks, +• +46 bulk cement trucks, +• +19 bulk nitrogen trucks, +• +3 bulk nitrogen tractor trailer combinations, +• +51 bulk sand trucks, +• +14 sand pneumatic trucks, and +• +26 connection trucks. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +Southeastern New Mexico, Oklahoma and the Gulf Coast region of +Louisiana. We serve our offshore customers through six +stockpoint facilities located along the Gulf of Mexico in Texas +and Louisiana and our land-based customers through fourteen +stockpoint facilities in Texas, Louisiana, Oklahoma and New +Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to ensure that the products and systems are applied +effectively to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +Raw Materials — Our drilling and completion +fluids 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 — We operate a barite +grinding facility with two barite grinding mills in Houma, +Louisiana. This facility allows us to grind raw barite into the +powder additive used in drilling fluids. +Other Equipment — We own and operate 20 trucks +and 92 trailers and lease another 34 trucks which are used to +transport drilling and completion fluids and related equipment. +5 +Table of Contents +Oil and +Natural Gas Operations +General — We have been engaged in the +development, exploration, acquisition and production of oil and +natural gas. Through October 31, 2007, we served as +operator with respect to several properties and were actively +involved in the development, exploration, acquisition and +production of oil and natural gas. Effective November 1, +2007, we sold the related operations portion of our exploration +and production business. We continue to own and invest in oil +and natural gas assets as a working interest owner. Our oil and +natural gas interests are located primarily in producing regions +of West and South Texas, Southeastern New Mexico, Utah and +Mississippi. +Customers +The customers of each of our three oil service business segments +are oil and natural gas operators. Our customer base includes +both major and independent oil and natural gas operators. During +2007, no single customer accounted for 10% or more of our +consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping +Businesses — Our land drilling and pressure +pumping businesses are highly competitive. At times, available +land drilling rigs and pressure pumping equipment exceed the +demand for such equipment. The equipment can also be moved from +one market to another in response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. State and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 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. +6 +Table of Contents +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a “major source.” As a +consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting +process may require capital expenditures in order to comply with +permit limits. +Risks and +Insurance +Our operations are subject to the many hazards inherent in the +drilling business, including: +• +accidents at the work location, +• +blow-outs, +• +cratering, +• +fires, and +• +explosions. +7 +Table of Contents +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for public liability +and property damage to others with respect to our operations. +However, such insurance may not be sufficient to protect us +against liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. However, it does not cover the full +replacement cost of the rigs and we do not carry insurance +against loss of earnings resulting from such damage. In view of +the difficulties that may be encountered in renewing such +insurance at reasonable rates, no assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +8 +Table of Contents +Employees +We had approximately 8,100 full-time employees at +December 31, 2007. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada, and our +pressure pumping division in the Appalachian Basin to a lesser +extent, are subject to slow periods of activity during the +Spring thaw. +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. +Item 1A. +Risk +Factors. +We wish to caution you that there are risks and uncertainties +that could affect our business. These risks and uncertainties +include, but are not limited to, the risks described below and +elsewhere in this Report, particularly found in “Forward +Looking Statements.” The following is not intended to be a +complete discussion of all potential risks or uncertainties, as +it is not possible to predict or identify all risk factors. +We are +Dependent on the Oil and Natural Gas Industry and Market Prices +for Oil and Natural Gas. Declines in Oil and Natural Gas Prices +Have Adversely Affected Our Operations. +Our revenue, profitability and rate of growth are substantially +dependent upon prevailing prices for natural gas and, to a +lesser extent, oil. For many years, oil and natural gas prices +and markets have been extremely volatile. Prices are affected by: +• +market supply and demand, +• +international military, political and economic +conditions, and +• +the ability of the Organization of Petroleum Exporting +Countries, commonly known as OPEC, to set and maintain +production and price targets. +All of these factors are beyond our control. During 2006, the +average market price of natural gas retreated from record highs +that were set in 2005. The price dropped from an average of +$8.98 per Mcf in 2005 to an average of $6.94 per Mcf in 2006 and +an average of $7.18 per Mcf in 2007. This resulted in our +customers moderating their increase in drilling activities in +2007. This moderation combined with the reactivation and +construction of new land drilling rigs in the United States has +resulted in excess capacity compared to recent demand. +Additionally, drilling activity in Canada has slowed +significantly. As a result of these factors, our average number +of rigs operating declined to 244 in 2007 compared to 296 in +2006. We expect oil and natural gas prices to continue to be +volatile and to affect our financial condition, operations and +ability to access sources of capital. A significant decrease in +market prices for natural gas could result in a material +decrease in demand for drilling rigs and adversely affect our +operating results. +A +General Excess of Operable Land Drilling Rigs Adversely Affects +Our Profit Margins Particularly in Times of Weaker +Demand. +The North American land drilling industry has experienced +periods of downturn in demand over the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins during +the downturn periods. +In addition to adverse effects that future declines in demand +could have on us, ongoing factors which could continue to +adversely affect utilization rates and pricing, even in an +environment of high oil and natural gas prices and increased +drilling activity, include: +• +movement of drilling rigs from region to region, +9 +Table of Contents +• +reactivation of land-based drilling rigs, or +• +construction of new drilling rigs. +As a result of an increase in drilling activity and increased +prices for drilling services in 2005 and 2006, construction of +new drilling rigs increased significantly in that time period. +The addition of new drilling rigs to the market has resulted in +excess capacity compared to demand, and construction of new +drilling rigs has moderated in 2007. We cannot predict either +the future level of demand for our contract drilling services or +future conditions in the oil and natural gas contract drilling +business. +Shortages +of Drill Pipe, Replacement Parts and Other Related Rig Equipment +Adversely Affects Our Operating Results. +During periods of increased demand for drilling services, the +industry has experienced shortages of drill pipe, replacement +parts and other related rig equipment. These shortages can cause +the price of these items to increase significantly and require +that orders for the items be placed well in advance of expected +use. These price increases and delays in delivery may require us +to increase capital and repair expenditures in our contract +drilling segment. Severe shortages could impair our ability to +operate our drilling rigs. +The +Oil Service Business Segments in Which We Operate Are Highly +Competitive with Excess Capacity, which Adversely Affect Our +Operating Results. +Our land drilling and pressure pumping businesses are highly +competitive. At times, available land drilling rigs and pressure +pumping equipment exceed the demand for such equipment. This +excess capacity has resulted in substantial competition for +drilling and pressure pumping contracts. The fact that drilling +rigs and pressure pumping equipment are mobile and can be moved +from one market to another in response to market conditions +heightens the competition in the industry. +We believe that price competition for drilling and pressure +pumping contracts will continue for the foreseeable future due +to the existence of available rigs and pressure pumping +equipment. +In recent years, many drilling and pressure pumping companies +have consolidated or merged with other companies. Although this +consolidation has decreased the total number of competitors, we +believe the competition for drilling and pressure pumping +services will continue to be intense. +The drilling and completion fluids services industry is highly +competitive. Price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Labor +Shortages Adversely Affect Our Operating Results. +During periods of increasing demand for contract drilling and +pressure pumping services, the industry experiences shortages of +qualified personnel. During these periods, our ability to +attract and retain sufficient qualified personnel to market and +operate our drilling rigs and pressure pumping equipment is +adversely affected, which negatively impacts both our operations +and profitability. Operationally, it is more difficult to hire +qualified personnel, which adversely affects our ability to +mobilize inactive rigs and pressure pumping equipment in +response to the increased demand for such services. +Additionally, wage rates for drilling and pressure pumping +personnel are likely to increase, resulting in higher operating +costs. +Continued +Growth Through Rig Acquisition is Not Assured. +We have increased our drilling rig fleet in the past through +mergers and acquisitions. The land drilling industry has +experienced significant consolidation, and there can be no +assurance that acquisition opportunities will be available in +the future. Additionally, we are likely to continue to face +intense competition from other companies for available +acquisition opportunities. +10 +Table of Contents +There can be no assurance that we will: +• +have sufficient capital resources to complete additional +acquisitions, +• +successfully integrate acquired operations and assets, +• +effectively manage the growth and increased size, +• +successfully deploy idle or stacked rigs, +• +maintain the crews and market share to operate drilling rigs +acquired, or +• +successfully improve our financial condition, results of +operations, business or prospects as a result of any completed +acquisition. +We may incur substantial indebtedness to finance future +acquisitions and also may issue equity securities or convertible +securities in connection with any such acquisitions. Debt +service requirements could represent a significant burden on our +results of operations and financial condition and the issuance +of additional equity would be dilutive to existing stockholders. +Also, continued growth could strain our management, operations, +employees and other resources. +The +Nature of our Business Operations Presents Inherent Risks of +Loss that, if not Insured or Indemnified Against, Could +Adversely Affect Our Operating Results. +Our operations are subject to many hazards inherent in the +contract drilling, pressure pumping, and drilling and completion +fluids businesses, which in turn could cause personal injury or +death, work stoppage, or serious damage to our equipment. Our +operations could also cause environmental and reservoir damages. +We maintain insurance coverage and have indemnification +agreements with many of our customers. However, there is no +assurance that such insurance or indemnification agreements +would adequately protect us against liability or losses from all +consequences of these hazards. Additionally, there can be no +assurance that insurance would be available to cover any or all +of these risks, or, even if available, that insurance premiums +or other costs would not rise significantly in the future, so as +to make the cost of 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, general liability +and equipment insurance coverages. +Violations +of Environmental Laws and Regulations Could Materially Adversely +Affect Our Operating Results. +The drilling of oil and natural gas wells is subject to various +Federal, state, foreign, and local laws, rules and regulations. +The cost of compliance with these laws and regulations could be +substantial. A failure to comply with these requirements could +expose us to substantial civil and criminal penalties. In +addition, Federal law imposes a variety of regulations on +“responsible parties” related to the prevention of oil +spills and liability for damages from such spills. As an owner +and operator of land-based drilling rigs, we may be deemed to be +a responsible party under Federal law. Our operations and +facilities are subject to numerous state and Federal +environmental laws, rules and regulations, including, without +limitation, laws concerning the containment and disposal of +hazardous substances, oil field waste and other waste materials, +the use of underground storage tanks and the use of underground +injection wells. +Some +of Our Contract Drilling Services are Provided Under Turnkey and +Footage Contracts, Which are Financially Risky. +At times, a portion of our contract drilling is performed under +turnkey and footage contracts, which involve significant risks. +Under turnkey drilling contracts, we contract to drill a well to +a certain depth under specified conditions at a fixed price. +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions at a fixed price per +foot. The risk to us under these types of drilling contracts are +greater than on a well drilled on a daywork basis. Unlike +daywork contracts, we must bear the cost of services until the +target depth is +11 +Table of Contents +reached. In addition, we must assume most of the risk associated +with the drilling operations, generally assumed by the operator +of the well on a daywork contract, including blowouts, loss of +hole from fire, machinery breakdowns and abnormal drilling +conditions. Accordingly, if severe drilling problems are +encountered in drilling wells under such contracts, we could +suffer substantial losses. +Anti-takeover +Measures in Our Charter Documents and Under State Law Could +Discourage an Acquisition and Thereby Affect the Related +Purchase Price. +We are a Delaware corporation subject to the Delaware General +Corporation Law, including Section 203, an anti-takeover +law enacted in 1988. We have also enacted certain anti-takeover +measures, including a stockholders’ rights plan. In +addition, our Board of Directors has the authority to issue up +to one million shares of preferred stock and to determine the +price, rights (including voting rights), conversion ratios, +preferences and privileges of that stock without further vote or +action by the holders of the common stock. As a result of these +measures and others, potential acquirers might find it more +difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our +securities of certain opportunities to sell or otherwise dispose +of the securities at above-market prices pursuant to any such +transactions. +Item 1B. +Unresolved +Staff Comments. +None. +Item 2. +Properties +Our corporate headquarters are located in Snyder, Texas and +include approximately 37,000 square feet of office and +storage space. These headquarters are located at 4510 Lamesa +Highway, Snyder, Texas, and our telephone number at that address +is +(325) 574-6300. +We also have administrative offices, yards and stockpoint +facilities in many of the areas in which we operate. The +facilities are primarily used to support day-to-day operations, +including the repair and maintenance of equipment as well as the +storage of equipment, inventory and supplies and to facilitate +administrative responsibilities and sales. +Contract Drilling Operations — Our drilling +services are supported by several administrative offices and +yard facilities located throughout our areas of operations +including Texas, New Mexico, Oklahoma, Colorado, Utah, Wyoming +and western Canada. +Pressure Pumping — Our pressure pumping +services are supported by several offices and yard facilities +located throughout our areas of operations including +Pennsylvania, Ohio, New York, West Virginia, Kentucky, +Tennessee, Wyoming and Colorado. +Drilling and Completion Fluids — Our drilling +and completion fluids services are supported by several +administrative offices and stockpoint facilities located +throughout our areas of operations including Texas, Louisiana, +New Mexico and Oklahoma. +We own our headquarters in Snyder, Texas, as well as several of +our other facilities. We also lease a number of facilities and +we do not believe that any one of the leased facilities is +individually material to our operations. We believe that our +existing facilities are suitable and adequate to meet our needs. +Item 3. +Legal +Proceedings. +We are party to various legal proceedings arising in the normal +course of our business. We do not believe that the outcome of +these proceedings, either individually or in the aggregate, will +have a material adverse effect on our results of operations, +cash flows or financial condition. +Item 4. +Submission +of Matters to a Vote of Security Holders. +None. +12 +Table of Contents +PART II +Item 5. +Market +for Registrant’s Common Equity, Related Stockholder Matters +and Issuer Purchases of Equity Securities. +(a) +Market +Information +Our common stock, par value $0.01 per share, is publicly traded +on the Nasdaq National Market and is quoted under the symbol +“PTEN.” Our common stock is included in the S&P +MidCap 400 Index and several other market indexes. The following +table provides high and low sales prices of our common stock for +the periods indicated: +High +Low +2007: +First quarter +$ +24.89 +$ +21.13 +Second quarter +27.66 +22.17 +Third quarter +26.48 +20.79 +Fourth quarter +23.22 +18.44 +2006: +First quarter +$ +38.49 +$ +25.61 +Second quarter +35.65 +25.24 +Third quarter +29.11 +21.84 +Fourth quarter +28.21 +20.81 +(b) +Holders +As of February 15, 2008, there were approximately 2,100 +holders of record of our common stock. +(c) +Dividends +and Buyback Program +We paid cash dividends during the years ended December 31, +2007 and 2006 as follows: +Per Share +Total +(In thousands) +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends declared and paid +$ +0.44 +$ +68,561 +2006: +Paid on March 30, 2006 +$ +0.04 +$ +6,906 +Paid on June 30, 2006 +0.08 +13,413 +Paid on September 29, 2006 +0.08 +13,024 +Paid on December 29, 2006 +0.08 +12,482 +Total cash dividends declared and paid +$ +0.28 +$ +45,825 +13 +Table of Contents +On February 13, 2008, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.12 per +share to be paid on March 28, 2008 to holders of record as +of March 12, 2008. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +The table below sets forth the information with respect to +purchases of our common stock made by us during the quarter +ended December 31, 2007. +Approximate +Total number +dollar value +of shares +of shares +(or units) +that may yet +purchased as +be purchased +part of +under the +Total number +Average price +publicly announced +plans or +of shares +paid per +plans or +programs +Period covered +purchased +share +programs(1) +(In thousands)(1) +October +1–31, +2007 +— +$ +— +— +$ +199,726 +November +1–30, +2007(2) +254,126 +$ +18.87 +250,000 +$ +195,009 +December +1–31, +2007 +783,850 +$ +19.60 +783,850 +$ +179,646 +Total +1,037,976 +$ +19.42 +1,033,850 +$ +179,646 +(1) +On August 1, 2007, our Board of Directors approved a stock +buyback program authorizing purchases of up to $250 million +of our common stock in open market or privately negotiated +transactions. +(2) +On November 30, 2007, we purchased 4,126 shares from +employees to provide the respective employees with the funds +necessary to satisfy their tax withholding obligations with +respect to the vesting of restricted shares on that date. The +price paid was $18.85 per share, which was the closing price of +our common stock on November 30, 2007. +(d) +Securities +Authorized for Issuance Under Equity Compensation +Plans +Equity compensation to our employees, officers and directors as +of December 31, 2007 follows: +Equity Compensation Plan Information +Number of +Securities Remaining +Number of +Available for +Securities to +Future Issuance +be Issued +Weighted-Average +under Equity +upon Exercise +Exercise Price +Compensation Plans +of Outstanding +of Outstanding +(Excluding Securities +Options, Warrants +Options, Warrants +Reflected in +Plan Category +and Rights +and Rights +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved by security holders(1) +6,733,337 +$ +18.27 +2,283,045 +Equity compensation plans not approved by security holders(2) +669,747 +$ +9.91 +— +Total +7,403,084 +$ +17.52 +2,283,045 +(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, officers +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 +14 +Table of Contents +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. +(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 officers 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. +15 +Table of Contents +(e) +Performance +Graph +The following graph compares the cumulative stockholder return +of our common stock for the period from December 31, 2002 +through December 31, 2007, with the cumulative total return +of the Standard & Poors 500 Stock Index, the +Standard & Poors MidCap Index, the Oilfield Service +Index and a peer group determined by us. Our peer group consists +of Grey Wolf, Inc., Helmerich & Payne, Inc., Nabors +Industries, Ltd., Pioneer Drilling Co. and Unit Corp. All of the +companies in our peer group are providers of land-based drilling +services. The graph assumes investment of $100 on +December 31, 2002 and reinvestment of all dividends. +Fiscal Year Ended December 31, +2002 +2003 +2004 +2005 +2006 +2007 +Company/Index +($) +($) +($) +($) +($) +($) +Patterson-UTI Energy, Inc. +100.00 +109.15 +129.56 +220.73 +157.34 +134.84 +Peer Group Index +100.00 +113.82 +147.78 +225.64 +182.13 +189.00 +S&P 500 Stock Index +100.00 +128.68 +142.69 +149.70 +173.34 +182.87 +Oilfield Service Index (OSX) +100.00 +116.47 +157.50 +236.16 +269.34 +393.90 +S&P MidCap Index +100.00 +135.62 +157.97 +177.81 +196.15 +211.80 +The foregoing graph is based on historical data and is not +necessarily indicative of future performance. This graph shall +not be deemed to be “soliciting material” or to be +“filed” with the SEC or subject to the Regulations of +14A or 14C under the Exchange Act or to the liabilities of +Section 18 under such act. +16 +Table of Contents +Item 6. +Selected +Financial Data. +Our selected consolidated financial data as of December 31, +2007, 2006, 2005, 2004 and 2003, and for each of the five years +in the period ended December 31, 2007 should be read in +conjunction with “Management’s Discussion and Analysis +of Financial Condition and Results of Operations” and the +Consolidated Financial Statements and related Notes thereto, +included as Items 7 and 8, respectively, of this Report. +Certain reclassifications have been made to the historical +financial data to conform with the 2007 presentation. +Years Ended December 31, +2007 +2006 +2005 +2004 +2003 +(In thousands, except per share amounts) +Income Statement Data: +Operating revenues: +Contract drilling +$ +1,741,647 +$ +2,169,370 +$ +1,485,684 +$ +809,691 +$ +639,694 +Pressure pumping +202,812 +145,671 +93,144 +66,654 +46,083 +Drilling and completion fluids +128,098 +192,358 +122,011 +90,557 +69,230 +Oil and natural gas +41,637 +39,187 +39,616 +33,867 +21,163 +Total +2,114,194 +2,546,586 +1,740,455 +1,000,769 +776,170 +Operating costs and expenses: +Contract drilling +963,150 +1,002,001 +776,313 +556,869 +475,224 +Pressure pumping +105,273 +77,755 +54,956 +37,561 +26,184 +Drilling and completion fluids +108,752 +150,372 +98,530 +76,503 +61,424 +Oil and natural gas +10,864 +13,374 +9,566 +7,978 +4,808 +Depreciation, depletion, amortization and impairment +249,206 +196,370 +156,393 +122,800 +100,834 +Selling, general and administrative +64,623 +55,065 +39,110 +31,983 +27,685 +Embezzlement costs (recoveries) +(43,955 +) +3,081 +20,043 +19,122 +17,849 +(Gain) loss on disposal of assets +(16,545 +) +3,819 +(1,231 +) +(1,411 +) +(1,927 +) +Other operating expenses (income) +2,550 +5,585 +5,479 +897 +(2,193 +) +Total +1,443,918 +1,507,422 +1,159,159 +852,302 +709,888 +Operating income +670,276 +1,039,164 +581,296 +148,467 +66,282 +Other income +531 +4,670 +3,463 +680 +2,694 +Income before income taxes and cumulative effect of change in +accounting principle +670,807 +1,043,834 +584,759 +149,147 +68,976 +Income tax expense +232,168 +371,267 +212,019 +54,801 +25,320 +Income before cumulative effect of change in accounting principle +438,639 +672,567 +372,740 +94,346 +43,656 +Cumulative effect of change in accounting principle, net of +related income tax expense of $398 in 2006 and benefit of $287 +in 2003 +— +687 +— +— +(469 +) +Net income +$ +438,639 +$ +673,254 +$ +372,740 +$ +94,346 +$ +43,187 +Income before cumulative effect of change in accounting +principle per common share: +Basic +$ +2.83 +$ +4.07 +$ +2.19 +$ +0.57 +$ +0.27 +Diluted +$ +2.79 +$ +4.02 +$ +2.15 +$ +0.56 +$ +0.27 +17 +Table of Contents +Years Ended December 31, +2007 +2006 +2005 +2004 +2003 +(In thousands, except per share amounts) +Net income per common share: +Basic +$ +2.83 +$ +4.08 +$ +2.19 +$ +0.57 +$ +0.27 +Diluted +$ +2.79 +$ +4.02 +$ +2.15 +$ +0.56 +$ +0.26 +Cash dividends per common share +$ +0.44 +$ +0.28 +$ +0.16 +$ +0.06 +$ +— +Weighted average number of common shares outstanding: +Basic +154,755 +165,159 +170,426 +166,258 +161,272 +Diluted +156,997 +167,413 +173,767 +169,211 +164,572 +Balance Sheet Data: +Total assets +$ +2,465,199 +$ +2,192,503 +$ +1,795,781 +$ +1,256,785 +$ +1,039,521 +Borrowings under line of credit +50,000 +120,000 +— +— +— +Stockholders’ equity +1,896,030 +1,562,466 +1,367,011 +961,501 +789,814 +Working capital +227,577 +335,052 +382,448 +235,480 +198,399 +18 +Table of Contents +Item 7. +Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +This Item 7 contains forward-looking statements, which are +made pursuant to the “Safe Harbor” provisions of the +Private Securities Litigation Reform Act of 1995. +Management Overview — We are a leading provider +of contract services to the North American oil and natural gas +industry. Our services primarily involve the drilling, on a +contract basis, of land-based oil and natural gas wells and, to +a lesser extent, we provide pressure pumping services and +drilling and completion fluid services. In addition to the +aforementioned contract services, we have also engaged in the +development, exploration, acquisition and production of oil and +natural gas. For the three years ended December 31, 2007, +our operating revenues consisted of the following (dollars in +thousands): +2007 +2006 +2005 +Contract drilling +$ +1,741,647 +82 +% +$ +2,169,370 +84 +% +$ +1,485,684 +86 +% +Pressure pumping +202,812 +10 +145,671 +6 +93,144 +5 +Drilling and completion fluids +128,098 +6 +192,358 +8 +122,011 +7 +Oil and natural gas +41,637 +2 +39,187 +2 +39,616 +2 +$ +2,114,194 +100 +% +$ +2,546,586 +100 +% +$ +1,740,455 +100 +% +We provide our contract services to oil and natural gas +operators in many of the oil and natural gas producing regions +of North America. Our contract drilling operations are focused +in various regions of Texas, New Mexico, Oklahoma, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, South Dakota, Pennsylvania and Western Canada, while our +pressure pumping services are focused primarily in the +Appalachian Basin. Our drilling and completion fluids services +are provided to operators offshore in the Gulf of Mexico and on +land in Texas, Southeastern New Mexico, Oklahoma and the Gulf +Coast region of Louisiana. The oil and natural gas properties in +which we hold working interests are primarily located in West +and South Texas, Southeastern New Mexico, Utah and +Mississippi. +Typically, the profitability of our business is most readily +assessed by two primary indicators in our contract drilling +segment: our average number of rigs operating and our average +revenue per operating day. During 2007, our average number of +rigs operating was 244 compared to 296 in 2006 and 276 in 2005. +Our average revenue per operating day was $19,550 in 2007 +compared to $20,050 in 2006 and $14,770 in 2005. Our +consolidated net income for 2007 decreased by $235 million, +or 35%, as compared to 2006. This decrease was primarily due to +our contract drilling segment experiencing a decrease in the +average number of rigs operating, a decrease in the average +revenue per operating day and an increase in the average costs +per operating day in 2007 as compared to 2006. +Our revenues, profitability and cash flows are highly dependent +upon the market prices of oil and natural gas. During periods of +improved commodity prices, the capital spending budgets of oil +and natural gas operators tend to expand, which results in +increased demand for our contract services. Conversely, in +periods when these commodity prices deteriorate, the demand for +our contract services generally weakens and we experience +downward pressure on pricing for our services. In addition, our +operations are highly impacted by competition, the availability +of excess equipment, labor issues and various other factors +which are more fully described as “Risk Factors” in +Item 1A of this Annual Report. +We believe that the liquidity shown on our balance sheet as of +December 31, 2007, which includes approximately +$228 million in working capital (including +$17.4 million in cash) and $266 million available +under a $375 million line of credit, provides us with the +ability to pursue acquisition opportunities, expand into new +regions, make improvements to our assets, pay cash dividends and +survive downturns in our industry. +Commitments and Contingencies — We maintain +letters of credit in the aggregate amount of $59.4 million +for the benefit of various insurance companies as collateral for +retrospective premiums and retained losses which could become +payable under the terms of the underlying insurance contracts. +These letters of credit expire at various times during each +calendar year. No amounts have been drawn under the letters of +credit. +As of December 31, 2007, we had non-cancelable commitments +to purchase approximately $83.0 million of equipment. +19 +Table of Contents +A receiver was appointed to take control of and liquidate the +assets of our former CFO in connection with his embezzlement of +Company funds. In May 2007, the court approved a plan of +distribution for the assets recovered by the receiver. We expect +to recover a total of approximately $44.5 million pursuant +to the approved plan, and we have recognized this recovery in +our consolidated statement of income in 2007, net of +professional fees incurred as a result of the embezzlement. As +of December 31, 2007, we had received cash payments from +the receiver of approximately $41.2 million, with the +remaining $3.3 million of the recovery consisting of notes +receivable, investments and other assets that are being +transferred to us. +Trading and investing — We have not engaged in +trading activities that include high-risk securities, such as +derivatives and non-exchange traded contracts. We invest cash +primarily in highly liquid, short-term investments such as +overnight deposits, money markets and highly rated municipal and +commercial bonds. +Description of business — We conduct our +contract drilling operations in Texas, New Mexico, Oklahoma, +Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, +Montana, North Dakota, South Dakota, Pennsylvania and western +Canada. For the years ended December 31, 2007, 2006 and +2005, revenue earned outside of the United States was +$72.9 million, $98.5 million and $84.4 million, +respectively. Additionally, we had long-lived assets located +outside of the United States of $91.6 million, +$78.9 million and $60.7 million as of +December 31, 2007, 2006 and 2005, respectively. As of +December 31, 2007, we had 350 currently marketable +land-based drilling rigs. We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. These services consist primarily of well stimulation and +cementing for completion of new wells and remedial work on +existing wells. We provide drilling fluids, completion fluids +and related services to oil and natural gas operators offshore +in the Gulf of Mexico and on land in Texas, Southeastern New +Mexico, Oklahoma and the Gulf Coast region of Louisiana. +Drilling and completion fluids are used by oil and natural gas +operators during the drilling process to control pressure when +drilling oil and natural gas wells. We also invest on a working +interest basis in production of oil and natural gas. +Critical +Accounting Policies +In addition to established accounting policies, our consolidated +financial statements are impacted by certain estimates and +assumptions made by management. The following is a discussion of +our critical accounting policies pertaining to property and +equipment, oil and natural gas properties, goodwill, revenue +recognition and the use of estimates. +Property and equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our assets +for impairment when events or changes in circumstances indicate +that the carrying values of certain assets either exceed their +respective fair values or may not be recovered over their +estimated remaining useful lives. The cyclical nature of our +industry has resulted in fluctuations in rig utilization over +periods of time. Management believes that the contract drilling +industry will continue to be cyclical and rig utilization will +fluctuate. Based on management’s expectations of future +trends, we estimate future cash flows over the life of the +respective assets in our assessment of impairment. These +estimates of cash flows are based on historical cyclical trends +in the industry as well as management’s expectations +regarding the continuation of these trends in the future. +Provisions for asset impairment are charged to income when +estimated future cash flows, on an undiscounted basis, are less +than the asset’s net book value. Impairment charges are +recorded based on discounted cash flows. There were no material +impairment charges related to property and equipment during the +years 2007, 2006 or 2005. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. In accordance with Statement of Financial +Accounting Standards No. 19, “Financial Accounting and +Reporting by Oil and Gas Producing Companies,” +(“SFAS No. 19”) costs of exploratory +20 +Table of Contents +wells are initially capitalized to wells in progress until the +outcome of the drilling is known. We review wells in progress +quarterly to determine whether sufficient progress is being made +in assessing the reserves and the economic operating viability +of the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project 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 field. We review our proved oil +and natural gas properties for impairment when an event occurs +such as downward revisions in reserve estimates or decreases in +oil and natural gas prices. Proved properties are grouped by +field and undiscounted cash flow estimates are prepared +internally and reviewed by an independent petroleum engineer. If +the net book value of a field exceeds its undiscounted cash flow +estimate, impairment expense is measured and recognized as the +difference between its net book value and discounted cash flow. +Unproved oil and natural gas properties are reviewed quarterly +to determine impairment. The intent to drill, lease expiration +and abandonment of area are considered. Assessment of impairment +is made on a +lease-by-lease +basis. If an unproved property is determined to be impaired, +then costs related to that property are expensed. Impairment +expense of approximately $3.9 million, $5.0 million +and $4.4 million for the years ended December 31, +2007, 2006 and 2005, respectively, is included in depreciation, +depletion and impairment in the accompanying financial +statements. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. As such, +we assess impairment of our goodwill annually as of December 31 +or on an interim basis if events or circumstances indicate that +the fair value of the asset has decreased below its carrying +value. +Revenue recognition — 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. We recognize reimbursements +received from third parties for out-of-pocket expenses incurred +as revenues and account for out-of-pocket expenses as direct +costs. +Use of estimates — The preparation of financial +statements in conformity with accounting principles generally +accepted in the United States of America requires management to +make certain estimates and assumptions that affect the reported +amounts of assets and liabilities and disclosures of contingent +assets and liabilities at the date of the financial statements +and the reported amounts of revenues and expenses during the +reporting period. Actual results could differ from such +estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +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. +21 +Table of Contents +Liquidity +and Capital Resources +As of December 31, 2007, we had working capital of +$228 million including cash and cash equivalents of +$17.4 million. For 2007, our sources of cash flow included: +• +$812 million from operating activities, +• +$34.2 million in proceeds from the disposal of property and +equipment, and +• +$3.2 million from the exercise of stock options and related +tax benefits associated with stock-based compensation. +During 2007, we used $70.9 million to repurchase shares of +our common stock, $68.6 million to pay dividends on our +common stock, $70.0 million to repay borrowings under our +line of credit, $29.0 million to acquire three electric +land-based drilling rigs and $608 million: +• +to make capital expenditures for the betterment and +refurbishment of our drilling rigs, +• +to acquire and procure drilling equipment and facilities to +support our drilling operations, +• +to fund capital expenditures for our pressure pumping and +drilling and completion fluids divisions, and +• +to fund leasehold acquisition and exploration and development of +oil and natural gas properties. +As of December 31, 2007, we had $50.0 million in +borrowings outstanding under our $375 million revolving +line of credit and $59.4 million in outstanding letters of +credit such that we had available borrowing capacity of +approximately $266 million at December 31, 2007. +We paid cash dividends during the year ended December 31, +2007 as follows: +Per Share +Total +(In thousands) +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends declared and paid +$ +0.44 +$ +68,561 +On February 13, 2008, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.12 per +share to be paid on March 28, 2008 to holders of record as +of March 12, 2008. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +On August 1, 2007, our Board of Directors approved a stock +buyback program (“2007 Program”), authorizing +purchases of up to $250 million of our common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2007, we purchased 3,308,850 shares +of our common stock under the 2007 Program at a cost of +approximately $70.4 million. As of December 31, 2007, +we are authorized to purchase approximately $180 million of +our outstanding common stock under the 2007 Program. +We believe that the current level of cash and short-term +investments, together with cash generated from operations, +should be sufficient to meet our capital needs. From time to +time, acquisition opportunities are evaluated. The timing, size +or success of any acquisition and the associated capital +commitments are unpredictable. Should opportunities for growth +requiring capital arise, we believe we would be able to satisfy +these needs through a combination of working capital, cash +generated from operations, our existing credit facility and +additional debt or equity financing. However, there can be no +assurance that such capital would be available. +22 +Table of Contents +Contractual +Obligations +The following table presents information with respect to our +contractual obligations as of December 31, 2007 (dollars in +thousands): +Payments Due by Period +Less Than 1 +More Than 5 +Total +Year +1-3 Years +3-5 Years +Years +Borrowings under line of credit(1) +$ +50,000 +$ +— +$ +50,000 +$ +— +$ +— +Commitments to purchase equipment(2) +82,998 +82,998 +— +— +— +$ +132,998 +$ +82,998 +$ +50,000 +$ +— +$ +— +(1) +Our line of credit is a revolving line of credit that matures on +December 16, 2009. So long as we are in compliance with our +obligations under the credit agreement, no principal repayments +are required until maturity. +(2) +Represents non-cancelable commitments to purchase equipment to +be delivered throughout 2008. +Off-Balance +Sheet Arrangements +We had no off-balance sheet arrangements at December 31, +2007. +Results +of Operations +Comparison +of the years ended December 31, 2007 and 2006 +The following tables summarize operations by business segment +for the years ended December 31, 2007 and 2006: +Year Ended December 31, +Contract Drilling +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +1,741,647 +$ +2,169,370 +(19.7 +)% +Direct operating costs +$ +963,150 +$ +1,002,001 +(3.9 +)% +Selling, general and administrative +$ +5,893 +$ +7,313 +(19.4 +)% +Depreciation +$ +213,812 +$ +168,607 +26.8 +% +Operating income +$ +558,792 +$ +991,449 +(43.6 +)% +Operating days +89,095 +108,192 +(17.7 +)% +Average revenue per operating day +$ +19.55 +$ +20.05 +(2.5 +)% +Average direct operating costs per operating day +$ +10.81 +$ +9.26 +16.7 +% +Average rigs operating +244 +296 +(17.6 +)% +Capital expenditures +$ +539,506 +$ +531,087 +1.6 +% +The demand for our contract drilling services is impacted by the +market price of oil and, to a larger extent, natural gas. +However, the reactivation and construction of new land drilling +rigs in the United States has resulted in excess capacity +compared to recent demand. Additionally, drilling activity in +Canada has decreased significantly. As a result, our average +rigs operating declined to 244 in 2007 from 296 in 2006. The +average market price of natural gas for each of the fiscal +quarters and full years in 2007 and 2006 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2007: +Average natural gas price(1) +$ +7.44 +$ +7.76 +$ +6.35 +$ +7.19 +$ +7.18 +2006: +Average natural gas price(1) +$ +7.93 +$ +6.74 +$ +6.26 +$ +6.87 +$ +6.94 +23 +Table of Contents +(1) +The average natural gas price above represents the Henry Hub +Spot price as reported by the United States Energy Information +Administration. +Revenues in 2007 decreased as compared to 2006 as a result of +decreases in the number of operating days and in the average +revenues per operating day. Direct operating costs in 2007 +decreased as compared to 2006 as a result of the decreased +number of operating days, largely offset by an increase in the +average direct operating costs per operating day. The increase +in average direct operating costs per day resulted primarily +from increased compensation costs and an increase in the cost of +maintenance for our drilling rigs. Operating days, average rigs +operating and average revenue per operating day decreased in +2007 as a result of decreased demand for our contract drilling +services resulting from the excess capacity discussed above. +Selling, general and administrative expense decreased primarily +as a result of the transfer of certain administrative staff to +our corporate segment. Significant capital expenditures have +been incurred in both 2007 and 2006 to activate additional +drilling rigs, to modify and upgrade our drilling rigs and to +acquire additional related equipment such as drill pipe, drill +collars, engines, fluid circulating systems, rig hoisting +systems and safety enhancement equipment. The increase in +depreciation expense is a result of the capital expenditures +discussed above. +Year Ended December 31, +Pressure Pumping +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +202,812 +$ +145,671 +39.2 +% +Direct operating costs +$ +105,273 +$ +77,755 +35.4 +% +Selling, general and administrative +$ +18,971 +$ +13,185 +43.9 +% +Depreciation +$ +14,311 +$ +9,896 +44.6 +% +Operating income +$ +64,257 +$ +44,835 +43.3 +% +Total jobs +14,094 +11,650 +21.0 +% +Average revenue per job +$ +14.39 +$ +12.50 +15.1 +% +Average direct operating costs per job +$ +7.47 +$ +6.67 +12.0 +% +Capital expenditures +$ +47,582 +$ +41,262 +15.3 +% +Revenues and direct operating costs increased as a result of the +increased number of jobs, as well as an increase in the average +revenue and average direct operating costs per job. The increase +in jobs was attributable to increased demand for our services +and increased operating capacity. Increased average revenue per +job was due to increased pricing for our services and an +increase in the number of larger jobs being driven by demand for +services associated with unconventional reservoirs in the +Appalachian basin. Average direct operating costs per job +increased as a result of increases in compensation, maintenance +and the cost of materials used in our operations, as well as an +increase in the number of larger jobs. Selling, general and +administrative expense increased primarily as a result of +expenses to support the expanding operations of the pressure +pumping segment. Significant capital expenditures have been +incurred in both 2007 and 2006 to add capacity, expand our areas +of operation and modify and upgrade existing equipment. The +increase in depreciation expense is a result of the capital +expenditures discussed above. +Year Ended December 31, +Drilling and Completion Fluids +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +128,098 +$ +192,358 +(33.4 +)% +Direct operating costs +$ +108,752 +$ +150,372 +(27.7 +)% +Selling, general and administrative +$ +9,958 +$ +10,521 +(5.4 +)% +Depreciation +$ +2,860 +$ +2,706 +5.7 +% +Operating income +$ +6,528 +$ +28,759 +(77.3 +)% +Capital expenditures +$ +3,082 +$ +4,222 +(27.0 +)% +Revenues and direct operating costs decreased as a result of a +decrease in the number of large jobs offshore in the Gulf of +Mexico caused primarily by a slowdown in drilling activity +during 2007 as compared to 2006. +24 +Table of Contents +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2007 +2006 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +41,637 +$ +39,187 +6.3 +% +Direct operating costs +$ +10,864 +$ +13,374 +(18.8 +)% +Selling, general and administrative +$ +2,365 +$ +2,785 +(15.1 +)% +Depreciation, depletion and impairment +$ +17,410 +$ +14,368 +21.2 +% +Operating income +$ +10,998 +$ +8,660 +27.0 +% +Capital expenditures +$ +17,516 +$ +21,198 +(17.4 +)% +Average net daily oil production (Bbls) +971 +983 +(1.2 +)% +Average net daily gas production (Mcf) +4,996 +5,143 +(2.9 +)% +Average oil sales price (per Bbl) +$ +68.82 +$ +63.83 +7.8 +% +Average gas sales price (per Mcf) +$ +7.37 +$ +6.82 +8.1 +% +Revenues increased due to an increase in the average sales price +of both oil and natural gas in 2007 compared to 2006. Average +net daily oil and natural gas production decreased in 2007 +primarily due to the sale of certain properties in the first +half of 2007. The decrease in direct operating costs is +primarily due to a decrease of approximately $3.0 million +in costs associated with the abandonment of exploratory wells in +2007 compared to 2006. Selling, general and administrative +expenses decreased in 2007 primarily due to the transfer in the +fourth quarter of the operating responsibilities associated with +oil and natural gas wells resulting in reduced headcount in our +oil and natural gas production and exploration segment. +Depreciation, depletion and impairment expense in 2007 includes +approximately $3.9 million incurred to impair certain oil +and natural gas properties compared to approximately +$5.0 million incurred to impair certain oil and natural gas +properties in 2006. Depletion expense increased approximately +$4.7 million primarily due to the completion of new wells +in 2007. +Year Ended December 31, +Corporate and Other +2007 +2006 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +27,436 +$ +21,261 +29.0 +% +Depreciation +$ +813 +$ +793 +2.5 +% +Other operating expenses +$ +2,550 +$ +5,585 +(54.3 +)% +Embezzlement costs (recoveries) +$ +(43,955 +) +$ +3,081 +N/A +% +(Gain) loss on disposal of assets +$ +(16,545 +) +$ +3,819 +N/A +% +Interest income +$ +2,355 +$ +5,925 +(60.3 +)% +Interest expense +$ +2,187 +$ +1,602 +36.5 +% +Other income +$ +363 +$ +347 +4.6 +% +Capital expenditures +$ +— +$ +150 +(100.0 +)% +Selling, general and administrative expense increased primarily +as a result of compensation expense related to transfers of +certain administrative staff from our drilling segment to our +corporate segment as well as increases in stock-based +compensation expense. Other operating expenses decreased due to +a decrease in bad debt expense of $2.9 million. In 2007, we +sold certain oil and natural gas properties resulting in a gain +of $21.6 million This gain was reduced by approximately +$5.1 million in losses associated with the disposal of +other assets. Gains and losses on the disposal of assets are +considered as part of our corporate activities due to the fact +that such transactions relate to decisions of the executive +management group regarding corporate strategy. Embezzlement +costs (recoveries) in 2007 includes an expected recovery of +$44.5 million reduced by professional fees incurred as a +result of the embezzlement. Embezzlement costs (recoveries) in +2006 include professional fees incurred as a result of the +embezzlement reduced by insurance proceeds of $2.3 million. +25 +Table of Contents +Comparison +of the years ended December 31, 2006 and 2005 +The following tables summarize operations by business segment +for the years ended December 31, 2006 and 2005: +Year Ended December 31, +Contract Drilling +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +2,169,370 +$ +1,485,684 +46.0 +% +Direct operating costs +$ +1,002,001 +$ +776,313 +29.1 +% +Selling, general and administrative +$ +7,313 +$ +5,069 +44.3 +% +Depreciation +$ +168,607 +$ +131,740 +28.0 +% +Operating income +$ +991,449 +$ +572,562 +73.2 +% +Operating days +108,192 +100,591 +7.6 +% +Average revenue per operating day +$ +20.05 +$ +14.77 +35.7 +% +Average direct operating costs per operating day +$ +9.26 +$ +7.72 +19.9 +% +Average rigs operating +296 +276 +7.2 +% +Capital expenditures +$ +531,087 +$ +329,073 +61.4 +% +Our average number of rigs operating increased to 296 in 2006 +from 276 in 2005. The average market price of natural gas for +each of the fiscal quarters and full years in 2006 and 2005 +follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2006: +Average natural gas price(1) +$ +7.93 +$ +6.74 +$ +6.26 +$ +6.87 +$ +6.94 +2005: +Average natural gas price(1) +$ +6.62 +$ +7.14 +$ +9.82 +$ +12.64 +$ +8.98 +(1) +The average natural gas price above represents the Henry Hub +Spot price as reported by the United States Energy Information +Administration. +26 +Table of Contents +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 cost per +operating day. Operating days and average rigs operating +increased as a result of increased demand for our contract +drilling services and the increase in the number of marketable +rigs in our fleet due to our rig activation program. Average +revenue per operating day increased as a result of increased +demand and pricing for our drilling services. Average direct +operating costs per operating day increased primarily as a +result of increased compensation costs and an increase in the +cost of maintenance for our rigs. Significant capital +expenditures were incurred to activate additional drilling rigs, +to modify and upgrade our drilling rigs and to acquire +additional related equipment such as drill pipe, drill collars, +engines, fluid circulating systems, rig hoisting systems and +safety enhancement equipment. The increase in depreciation +expense was a result of the capital expenditures and +acquisitions. +Year Ended December 31, +Pressure Pumping +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +145,671 +$ +93,144 +56.4 +% +Direct operating costs +$ +77,755 +$ +54,956 +41.5 +% +Selling, general and administrative +$ +13,185 +$ +9,430 +39.8 +% +Depreciation +$ +9,896 +$ +7,094 +39.5 +% +Operating income +$ +44,835 +$ +21,664 +107.0 +% +Total jobs +11,650 +9,615 +21.2 +% +Average revenue per job +$ +12.50 +$ +9.69 +29.0 +% +Average direct operating costs per job +$ +6.67 +$ +5.72 +16.6 +% +Capital expenditures +$ +41,262 +$ +25,508 +61.8 +% +Revenues and direct operating costs increased as a result of the +increased number of jobs, as well as an increase in the average +revenue and average direct operating cost per job. The increase +in jobs was attributable to increased demand for our services +and increased operating capacity which has been added. Increased +average revenue per job was due to increased pricing for our +services and an increase in the number of larger jobs. Average +direct operating costs per job increased as a result of +increases in compensation and the cost of materials used in our +operations, as well as an increase in the number of larger jobs. +Selling, general and administrative expense increased as a +result of additional expenses to support the expanded operations +of the pressure pumping segment. Significant capital +expenditures were incurred to add capacity and modify and +upgrade existing equipment. The increase in depreciation expense +was a result of the capital expenditures discussed above. +Year Ended December 31, +Drilling and Completion Fluids +2006 +2005 +% Change +(Dollars in thousands) +Revenues +$ +192,358 +$ +122,011 +57.7 +% +Direct operating costs +$ +150,372 +$ +98,530 +52.6 +% +Selling, general and administrative +$ +10,521 +$ +8,912 +18.1 +% +Depreciation +$ +2,706 +$ +2,368 +14.3 +% +Operating income +$ +28,759 +$ +12,201 +135.7 +% +Capital expenditures +$ +4,222 +$ +3,042 +38.8 +% +27 +Table of Contents +Revenues and direct operating costs increased primarily as a +result of an increase in large jobs offshore in the Gulf of +Mexico during 2006. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2006 +2005 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +39,187 +$ +39,616 +(1.1 +)% +Direct operating costs +$ +13,374 +$ +9,566 +39.8 +% +Selling, general and administrative +$ +2,785 +$ +2,189 +27.2 +% +Depreciation, depletion and impairment +$ +14,368 +$ +14,456 +(0.6 +)% +Operating income +$ +8,660 +$ +13,405 +(35.4 +)% +Capital expenditures +$ +21,198 +$ +17,163 +23.5 +% +Average net daily oil production (Bbls) +983 +860 +14.3 +% +Average net daily gas production (Mcf) +5,143 +7,016 +(26.7 +)% +Average oil sales price (per Bbl) +$ +63.83 +$ +54.30 +17.6 +% +Average gas sales price (per Mcf) +$ +6.82 +$ +7.64 +(10.7 +)% +Direct operating costs increased primarily due to +$4.2 million in costs associated with the abandonment of +exploratory wells. Depreciation, depletion and impairment +expense includes $5.0 million and $4.4 million +incurred during 2006 and 2005, respectively, to reflect the +impairment of certain oil and natural gas properties. Average +net daily oil production increased due to the completion of new +wells in 2006. Average net daily natural gas production +decreased as a result of production declines and the sale of +certain natural gas properties. +Year Ended December 31, +Corporate and Other +2006 +2005 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +21,261 +$ +13,510 +57.4 +% +Depreciation +$ +793 +$ +735 +7.9 +% +Other operating expenses +$ +5,585 +$ +5,479 +1.9 +% +Embezzlement costs +$ +3,081 +$ +20,043 +(84.6 +)% +(Gain) loss on disposal of assets +$ +3,819 +$ +(1,231 +) +N/A +% +Interest income +$ +5,925 +$ +3,551 +66.9 +% +Interest expense +$ +1,602 +$ +516 +210.5 +% +Other income +$ +347 +$ +428 +(18.9 +)% +Capital expenditures +$ +150 +$ +5,308 +(97.2 +)% +Selling, general and administrative expense increased primarily +as a result of an increase of $7.8 million in stock-based +compensation expense which was impacted by the adoption of a new +accounting standard in 2006 requiring the expensing of stock +options. Other operating expenses include bad debt expense of +$5.4 million and $1.2 million in 2006 and 2005, +respectively. Embezzlement costs in 2005 includes payments made +to or for the benefit of Jonathan D. Nelson, our former CFO, for +assets and services that were not received by the Company and in +2006 includes continuing professional fees incurred as a result +of the embezzlement, net of insurance proceeds of +$2.3 million received in connection with the loss. Interest +expense in 2006 increased due to borrowings under our line of +credit during 2006. +Income +Taxes +Year Ended December 31, +2007 +2006 +2005 +(Dollars in thousands) +Income before income tax +$ +670,807 +$ +1,043,834 +$ +584,759 +Income tax expense +232,168 +371,267 +212,019 +Effective tax rate +34.6 +% +35.6 +% +36.3 +% +28 +Table of Contents +The effective tax rate is a result of a Federal rate of 35.0% +adjusted as follows: +2007 +2006 +2005 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.4 +1.4 +1.8 +Permanent differences +(1.6 +) +(0.8 +) +(0.6 +) +Other, net +(0.2 +) +0.0 +0.1 +Effective tax rate +34.6 +% +35.6 +% +36.3 +% +The permanent differences indicated above are largely +attributable to the Domestic Production Activities Deduction. +The deduction was enacted as part of the American Jobs Creation +Act of 2004 effective for taxable years after December 31, +2004. The act allows a deduction of 3% in 2005 and 2006, 6% in +2007, 2008 and 2009, and 9% in 2010 and after on the lesser of +qualified production activities income or taxable income. +For tax purposes, we have Federal net operating loss +carryforwards of approximately $374,000 available at +December 31, 2007. We have alternative minimum tax credit +carryforwards of approximately $118,000 available at +December 31, 2007. The net operating loss carryforwards, if +unused, are scheduled to expire in 2019. The alternative minimum +tax credit may be carried forward indefinitely. +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 differences +between the book basis and tax basis in our assets. Deferred tax +assets and liabilities are measured using enacted tax rates +expected to apply to taxable income in the year in which those +temporary differences are expected to be settled. As a result of +fully recognizing the benefit of our deferred income taxes, we +incur deferred income tax expense as these benefits are +utilized. We incurred a deferred tax expense of approximately +$38.3 million in 2007, a deferred tax benefit of +approximately $4.1 million in 2006 and a deferred tax +expense of approximately $17.1 million in 2005. +Volatility +of Oil and Natural Gas Prices +Our revenue, profitability, and rate of growth are substantially +dependent upon prevailing prices for natural gas and, to a +lesser extent, oil. For many years, oil and natural gas prices +and markets have been volatile. Prices are affected by market +supply and demand factors as well as international military, +political and economic conditions, and the ability of OPEC to +set and maintain production and price targets. All of these +factors are beyond our control. During 2006, the average market +price of natural gas retreated from record highs that were set +in 2005. The price dropped from an average of $8.98 per Mcf in +2005 to an average of $6.94 per Mcf in 2006 and an average of +$7.18 per Mcf in 2007. This resulted in our customers moderating +their increase in drilling activities in 2007. This moderation +combined with the reactivation and construction of new land +drilling rigs in the United States has resulted in excess +capacity compared to recent demand. Additionally, drilling +activity in Canada has slowed significantly. As a result of +these factors, our average rigs operating declined to 244 in +2007 compared to 296 in 2006. We expect oil and natural gas +prices to continue to be volatile and to affect our financial +condition, operations and ability to access sources of capital. +A significant decrease in market prices for natural gas could +result in a material decrease in demand for drilling rigs and +adversely affect our operating 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 difficulty sustaining profit margins during the downturn +periods. +Impact of +Inflation +Inflation has not had a significant impact on our operations +during the three years in the period ended December 31, +2007. We believe that inflation will not have a significant +near-term impact on our financial position. +Recently +Issued Accounting Standards +In September 2006, the FASB issued Statement No. 157, +Fair Value Measurements (“FAS 157”). +FAS 157 defines fair value, establishes a framework for +measuring fair value in generally accepted accounting +principles, and +29 +Table of Contents +expands disclosures about fair value measurement. FAS 157 +is effective for financial statements issued for fiscal years +beginning after November 15, 2007 and interim periods +within those fiscal years. FAS 157 will be effective for us +beginning in the quarter ending March 31, 2008. The +application of FAS 157 is not expected to have a material +impact to us. +In February 2007, the FASB issued Statement No. 159, The +Fair Value Option for Financial Assets and Financial Liabilities +Including an Amendment of FASB Statement No. 115 +(“FAS 159”). FAS 159 permits entities to +choose to measure many financial instruments and certain other +items at fair value. FAS 159 is effective as of the +beginning of an entity’s first fiscal year that begins +after November 15, 2007 and will be effective for us +beginning in the quarter ending March 31, 2008. The +application of FAS 159 is not expected to have a material +impact to us. +In December 2007, the FASB issued Statement No. 141(R), +Business Combinations (“FAS 141(R)”) and +Statement No. 160, Noncontrolling Interests in +Consolidated Financial Statements, an amendment of ARB +No. 51 (“FAS 160”). FAS 141(R) is a +revision of Statement No. 141, Business +Combinations , and calls for significant changes from current +practice in accounting for business combinations. +FAS 141(R) is effective for business combinations for which +the acquisition date is on or after the beginning of the first +annual reporting period beginning on or after December 15, +2008. FAS 160 amends ARB 51 to establish accounting and +reporting standards for the noncontrolling interest in a +subsidiary and for the deconsolidation of a subsidiary. +FAS 160 is effective for fiscal years beginning on or after +December 15, 2008. Both FAS 141(R) and FAS 160 +will be effective for us beginning the quarter ending +March 31, 2009. The application of FAS 141(R) and +FAS 160 are not expected to have a material impact to us. +Item 7A. +Quantitative +and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk +associated with borrowings under our credit facility. The +revolving credit facility calls for periodic interest payments +at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at +the prime rate. The applicable rate above LIBOR is based upon +our debt to capitalization ratio. A 1% increase (100 basis +points) in LIBOR and the prime rate would result in additional +annual interest expense of approximately $500,000 based upon the +level of borrowings we had outstanding at December 31, 2007. +We conduct some business in Canadian dollars through our +Canadian land-based drilling operations. The exchange rate +between Canadian dollars and U.S. dollars has fluctuated +during the last several years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and +earnings of our Canadian operations will be reduced and the +value of our Canadian net assets will decline when they are +translated to U.S. dollars. +Item 8. +Financial +Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the +end of Part IV hereof beginning at +page F-1, +Index to Consolidated Financial Statements, and are incorporated +herein by this reference. +Item 9. +Changes +in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2007, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO +and CFO, as appropriate to allow timely decisions regarding +required disclosure. +30 +Table of Contents +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2007, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2007. +The effectiveness of our internal control over financial +reporting as of December 31, 2007 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and is incorporated by reference into Item 8 +of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. +Item 9B. +Other +Information +None. +31 +Table of Contents +PART III +The information required by Part III is omitted from this +Report because we will file a definitive proxy statement +pursuant to Regulation 14A of the Securities Exchange Act +of 1934 no later than 120 days after the end of the fiscal +year covered by this Report and certain information included +therein is incorporated herein by reference. +Item 10. +Directors, +Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 11. +Executive +Compensation. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 12. +Security +Ownership of Certain Beneficial Owners and Management and +Related Stockholder Matters. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +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. +32 +Table of Contents +PART IV +Item 15. +Exhibits +and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 +of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts +is filed herewith on +page S-1. +All other financial statement schedules have been omitted +because they are not applicable or the information required +therein is included elsewhere in the financial statements or +notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by +reference herein. +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as +amended (filed March 13, 1998 as Exhibit 10.1 to the +Company’s Registration Statement on +Form S-8 +(File +No. 333-47917) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock +Option Plan, as amended (filed November 4, 1997 as +Exhibit 10.1 to the Company’s Registration Statement +on +Form S-8 +(File +No. 333-39471) +and incorporated herein by reference).* +10 +.4 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.6 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.7 +Amended and Restated Patterson-UTI Energy, Inc. Non-Employee +Director Stock Option Plan(filed July 28, 2003 as +Exhibit 4.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +33 +Table of Contents +10 +.8 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.9 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.10 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed +August 9, 2004 as Exhibit 10.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.11 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed +August 9, 2004 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.12 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed +August 9, 2004 as Exhibit 10.4 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.13 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and John E. Vollmer III +(filed August 9, 2004 as Exhibit 10.6 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.15 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.16 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.18 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.19 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +William L. Moll, Jr. and Gregory W. Pipkin (filed April 28, +2004 as Exhibit 10.11 to the Company’s Annual Report +on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.20 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +34 +Table of Contents +10 +.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and William L. Moll, Jr. (filed +November 5, 2007 as Exhibit 10.7 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.27 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and William L. Moll, Jr., entered +into November 1, 2007 (filed November 5, 2007 as +Exhibit 10.12 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.28 +Credit Agreement dated as of December 17, 2004 among +Patterson-UTI Energy, Inc., as the Borrower, Bank of America, +N.A., as administrative agent, L/C Issuer and a Lender and the +other lenders and agents party thereto (filed on +December 23, 2004 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.29 +Commitment Increase and Joinder Agreement, dated as of +August 2, 2006, by and among Patterson-UTI Energy, Inc., +the guarantors party thereto, the lenders party thereto, and +Bank of America, N.A. as Administrative Agent, L/C Issuer and +Lender (filed August 21, 2006 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.30 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics +for Senior Financial Executives (filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. +35 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of Independent Registered Public +Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of +December 31, 2007 and 2006 +F-3 +Consolidated Statements of Income for the years +ended December 31, 2007, 2006 and 2005 +F-4 +Consolidated Statements of Changes In +Stockholders’ Equity for the years ended December 31, +2007, 2006 and 2005 +F-5 +Consolidated Statements of Changes In Cash Flows +for the years ended December 31, 2007, 2006 and 2005 +F-6 +Notes to Consolidated Financial Statements +F-7 +Financial Statement Schedule +S-1 +Subsidiaries of the Registrant +Consent of Independent Registered Public Accounting Firm +Certification of Chief Executive Officer +Certification of Chief Financial Officer +Certification of CEO and CFO Pursuant to Section 906 +F-1 +Table of Contents +Report of +Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of +Patterson-UTI Energy, Inc.: +In our opinion, the consolidated financial statements listed in +the accompanying index present fairly, in all material respects, +the financial position of Patterson-UTI Energy, Inc. and its +subsidiaries at December 31, 2007 and 2006, and the results +of their operations and their cash flows for each of the three +years in the period ended December 31, 2007 in conformity +with accounting principles generally accepted in the United +States of America. In addition, in our opinion, the financial +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 financial statements. Also in our +opinion, the Company maintained, in all material respects, +effective internal control over financial reporting as of +December 31, 2007, based on criteria established in +Internal Control — Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). The Company’s management is responsible +for these financial statements and financial statement schedule, +for maintaining effective internal control over financial +reporting and for its assessment of the effectiveness of +internal control over financial reporting, included in +Management’s Report on Internal Control over Financial +Reporting appearing under Item 9A. Our responsibility is to +express opinions on these financial statements, on the financial +statement schedule, and on the Company’s internal control +over financial reporting based on our integrated audits. We +conducted our audits in accordance with the standards of the +Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audits to obtain +reasonable assurance about whether the financial statements are +free of material misstatement and whether effective internal +control over financial reporting was maintained in all material +respects. Our audits of the financial statements included +examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by +management, and evaluating the overall financial statement +presentation. Our audit of internal control over financial +reporting included obtaining an understanding of internal +control over financial reporting, assessing the risk that a +material weakness exists, and testing and evaluating the design +and operating effectiveness of internal control based on the +assessed risk. Our audits also included performing such other +procedures as we considered necessary in the circumstances. We +believe that our audits provide a reasonable basis for our +opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 18, 2008 +F-2 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2007 +2006 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +17,434 +$ +13,385 +Accounts receivable, net of allowance for doubtful accounts of +$10,014 and $7,484 at December 31, 2007 and 2006, +respectively +373,279 +484,106 +Accrued Federal and state income taxes receivable +— +5,448 +Inventory +44,416 +43,947 +Deferred tax assets, net +35,370 +48,868 +Deposits on equipment purchases +1,650 +24,746 +Other +50,636 +32,170 +Total current assets +522,785 +652,670 +Property and equipment, net +1,841,404 +1,435,804 +Goodwill +96,198 +99,056 +Other +4,812 +4,973 +Total assets +$ +2,465,199 +$ +2,192,503 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable: +Trade +$ +133,330 +$ +138,372 +Accrued revenue distributions +4,221 +15,359 +Other +19,365 +18,424 +Accrued Federal and state income taxes payable +1,458 +— +Accrued expenses +136,834 +145,463 +Total current liabilities +295,208 +317,618 +Borrowings under line of credit +50,000 +120,000 +Deferred tax liabilities, net +219,490 +187,960 +Other +4,471 +4,459 +Total liabilities +569,169 +630,037 +Commitments and contingencies (see Note 9) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 177,385,808 and 176,656,401 issued and 153,942,800 and +156,542,512 outstanding at December 31, 2007 and 2006, +respectively +1,773 +1,766 +Additional paid-in capital +703,581 +681,069 +Retained earnings +1,716,620 +1,346,542 +Accumulated other comprehensive income +20,207 +8,390 +Treasury stock, at cost, 23,443,008 shares and +20,113,889 shares at December 31, 2007 and 2006, +respectively +(546,151 +) +(475,301 +) +Total stockholders’ equity +1,896,030 +1,562,466 +Total liabilities and stockholders’ equity +$ +2,465,199 +$ +2,192,503 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF INCOME +Year Ended December 31, +2007 +2006 +2005 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,741,647 +$ +2,169,370 +$ +1,485,684 +Pressure pumping +202,812 +145,671 +93,144 +Drilling and completion fluids +128,098 +192,358 +122,011 +Oil and natural gas +41,637 +39,187 +39,616 +2,114,194 +2,546,586 +1,740,455 +Operating costs and expenses: +Contract drilling +963,150 +1,002,001 +776,313 +Pressure pumping +105,273 +77,755 +54,956 +Drilling and completion fluids +108,752 +150,372 +98,530 +Oil and natural gas +10,864 +13,374 +9,566 +Depreciation, depletion and impairment +249,206 +196,370 +156,393 +Selling, general and administrative +64,623 +55,065 +39,110 +Embezzlement costs (recoveries) +(43,955 +) +3,081 +20,043 +(Gain) loss on disposal of assets +(16,545 +) +3,819 +(1,231 +) +Other operating expenses +2,550 +5,585 +5,479 +1,443,918 +1,507,422 +1,159,159 +Operating income +670,276 +1,039,164 +581,296 +Other income (expense): +Interest income +2,355 +5,925 +3,551 +Interest expense +(2,187 +) +(1,602 +) +(516 +) +Other +363 +347 +428 +531 +4,670 +3,463 +Income before income taxes and cumulative effect of change in +accounting principle +670,807 +1,043,834 +584,759 +Income tax expense (benefit): +Current +193,897 +375,373 +194,918 +Deferred +38,271 +(4,106 +) +17,101 +232,168 +371,267 +212,019 +Income before cumulative effect of change in accounting principle +438,639 +672,567 +372,740 +Cumulative effect of change in accounting principle, net of +related income tax expense of $398 +— +687 +— +Net income +$ +438,639 +$ +673,254 +$ +372,740 +Income before cumulative effect of change in accounting +principle per common share: +Basic +$ +2.83 +4.07 +$ +2.19 +Diluted +$ +2.79 +4.02 +$ +2.15 +Net income per common share: +Basic +$ +2.83 +$ +4.08 +$ +2.19 +Diluted +$ +2.79 +$ +4.02 +$ +2.15 +Weighted average number of common shares outstanding: +Basic +154,755 +165,159 +170,426 +Diluted +156,997 +167,413 +173,767 +Cash dividends per common share +$ +0.44 +$ +0.28 +$ +0.16 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Deferred +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Compensation +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2004 +171,626 +$ +1,716 +$ +597,280 +$ +(5,420 +) +$ +373,712 +$ +7,350 +$ +(13,137 +) +$ +961,501 +Issuance of restricted stock +305 +3 +8,040 +(8,043 +) +— +— +— +— +Amortization of deferred compensation expense +— +— +— +2,825 +— +— +— +2,825 +Forfeitures of restricted shares +(65 +) +— +(1,351 +) +1,351 +— +— +— +— +Exercise of stock options +4,043 +40 +43,434 +— +— +— +— +43,474 +Tax benefit related to stock-based compensation +— +— +24,748 +— +— +— +— +24,748 +Foreign currency translation adjustment (net of tax of $705) +— +— +— +— +— +1,215 +— +1,215 +Purchase of treasury stock +— +— +— +— +— +— +(12,153 +) +(12,153 +) +Payment of cash dividend (see Note 10) +— +— +— +— +(27,339 +) +— +— +(27,339 +) +Net income +— +— +— +— +372,740 +— +— +372,740 +Balance, December 31, 2005 +175,909 +1,759 +672,151 +(9,287 +) +719,113 +8,565 +(25,290 +) +1,367,011 +Elimination of deferred compensation due to change in accounting +principle +— +— +(9,287 +) +9,287 +— +— +— +— +Issuance of restricted stock +613 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(47 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +181 +2 +1,944 +— +— +— +— +1,946 +Tax benefit related to stock-based compensation +— +— +1,087 +— +— +— +— +1,087 +Stock based compensation, net of cumulative effect of change in +accounting principle +— +— +15,179 +— +— +— +— +15,179 +Foreign currency translation adjustment, (net of tax of $6) +— +— +— +— +— +(175 +) +— +(175 +) +Payment of cash dividend (see Note 10) +— +— +— +— +(45,825 +) +— +— +(45,825 +) +Purchase of treasury stock +— +— +— +— +— +— +(450,011 +) +(450,011 +) +Net income +— +— +— +— +673,254 +— +— +673,254 +Balance, December 31, 2006 +176,656 +1,766 +681,069 +— +1,346,542 +8,390 +(475,301 +) +1,562,466 +Issuance of restricted stock +601 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(101 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +230 +2 +2,048 +— +— +— +— +2,050 +Tax benefit related to stock-based compensation +— +— +1,105 +— +— +— +— +1,105 +Stock based compensation +— +— +19,364 +— +— +— +— +19,364 +Foreign currency translation adjustment, (net of tax of $6,755) +— +— +— +— +— +11,817 +— +11,817 +Payment of cash dividend (see Note 10) +— +— +— +— +(68,561 +) +— +— +(68,561 +) +Purchase of treasury stock +— +— +— +— +— +— +(70,850 +) +(70,850 +) +Net income +— +— +— +— +438,639 +— +— +438,639 +Balance, December 31, 2007 +177,386 +$ +1,773 +$ +703,581 +$ +— +$ +1,716,620 +$ +20,207 +$ +(546,151 +) +$ +1,896,030 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN CASH FLOWS +Year Ended December 31, +2007 +2006 +2005 +(In thousands) +Cash flows from operating activities: +Net income +$ +438,639 +$ +673,254 +$ +372,740 +Adjustments to reconcile net income to net cash provided by +operating activities: +Depreciation, depletion and impairment +249,206 +196,370 +156,393 +Provision for bad debts +2,550 +5,400 +1,231 +Dry holes and abandonments +1,309 +4,338 +— +Deferred income tax expense (benefit) +38,271 +(3,708 +) +17,101 +Tax benefit related to stock-based compensation +— +— +24,748 +Stock based compensation expense +19,364 +15,179 +2,825 +(Gain) loss on disposal of assets +(16,545 +) +3,819 +(1,253 +) +Changes in operating assets and liabilities: +Accounts receivable +112,353 +(67,417 +) +(208,248 +) +Income taxes receivable/payable +7,174 +(16,231 +) +7,068 +Inventory and other current assets +4,853 +(47,406 +) +(9,402 +) +Accounts payable +(40,317 +) +27,184 +60,860 +Accrued expenses +(6,104 +) +32,972 +32,514 +Other liabilities +1,471 +13,416 +3,902 +Net cash provided by operating activities +812,224 +837,170 +460,479 +Cash flows from investing activities: +Acquisitions +(29,000 +) +— +(73,577 +) +Purchases of property and equipment +(607,686 +) +(597,919 +) +(380,094 +) +Proceeds from disposal of assets +34,224 +10,934 +12,674 +Change in other assets +— +— +1,766 +Net cash used in investing activities +(602,462 +) +(586,985 +) +(439,231 +) +Cash flows from financing activities: +Purchases of treasury stock +(70,850 +) +(450,011 +) +(12,153 +) +Dividends paid +(68,561 +) +(45,825 +) +(27,339 +) +Tax benefit related to stock-based compensation +1,105 +1,087 +— +Proceeds from borrowings under line of credit +142,500 +274,000 +— +Repayment of borrowings under line of credit +(212,500 +) +(154,000 +) +— +Line of credit issuance costs +— +(342 +) +— +Proceeds from exercise of stock options +2,050 +1,946 +43,474 +Net cash provided by (used in) financing activities +(206,256 +) +(373,145 +) +3,982 +Effect of foreign exchange rate changes on cash +543 +(53 +) +(1,203 +) +Net increase (decrease) in cash and cash equivalents +4,049 +(123,013 +) +24,027 +Cash and cash equivalents at beginning of year +13,385 +136,398 +112,371 +Cash and cash equivalents at end of year +$ +17,434 +$ +13,385 +$ +136,398 +Supplemental disclosure of cash flow information: +Net cash paid during the year for: +Interest expense +$ +(1,808 +) +$ +(1,278 +) +$ +(418 +) +Income taxes +(176,281 +) +(377,847 +) +(156,709 +) +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., together with its wholly-owned subsidiaries, (collectively +referred to herein as “Patterson-UTI” or the +“Company”) is a leading provider of onshore contract +drilling services to major and independent oil and natural gas +operators in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +South Dakota, Pennsylvania and Western Canada. The Company +provides pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. The Company +provides drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast region of Louisiana. The Company owns and invests in +oil and natural gas assets as a working interest owner. The +Company’s oil and natural gas interests are located +primarily in producing regions of West and South Texas, +Southeastern New Mexico, Utah and Mississippi. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. The Company has +no controlling financial interests in any entity that is not a +wholly-owned subsidiary and which would require consolidation. +The U.S. dollar is the functional currency for all of the +Company’s operations except for its Canadian operations, +which use the Canadian dollar as their functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting, as described +below. The Company follows the percentage-of-completion method +of accounting for footage and daywork contract drilling +arrangements. Under the percentage-of-completion method, +management estimates are relied upon in the determination of the +total estimated expenses to be incurred drilling the well. Due +to the nature of turnkey contract drilling arrangements and +risks therein, the Company follows the completed contract method +of accounting for such arrangements. Under this method, all +drilling 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 — 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 at +least quarterly. Significant individual accounts receivable +balances and balances which have been outstanding greater than +90 days are reviewed individually for collectibility. +Account balances, when determined to be uncollectible, are +charged against the allowance. +F-7 +Table of Contents +Inventories — Inventories consist primarily of +chemical products to be used in conjunction with the +Company’s drilling and completion fluids and pressure +pumping activities. The inventories are stated at the lower of +cost or market, determined by the +first-in, +first-out method. +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change when +equipment becomes idle. The estimated useful lives, in years, +are defined below. +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and the economic operating viability +of the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project after one year following the completion of drilling, the +Company considers the costs of the well to be impaired and +recognizes the costs as expense. Geological and geophysical +costs, including seismic costs, and costs to carry and retain +undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful +exploratory type wells, consisting of lease and well equipment, +lease acquisition costs and intangible development costs, are +depreciated, depleted and amortized on the units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves of each respective field. The Company reviews its +proved oil and natural gas properties for impairment when an +event occurs such as downward revisions in reserve estimates or +decreases in oil and natural gas prices. Proved properties are +grouped by field and undiscounted cash flow estimates are +provided by an independent petroleum engineer. If the net book +value of a field exceeds its undiscounted cash flow estimate, +impairment expense is measured and recognized as the difference +between its net book value and discounted cash flow. Unproved +oil and natural gas properties are reviewed quarterly to +determine impairment. The Company’s intent to drill, lease +expiration and abandonment of area are considered. Assessment of +impairment is made on a +lease-by-lease +basis. If an unproved property is determined to be impaired, +costs related to that property are expensed. +Goodwill — Goodwill is considered to have an +indefinite 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. +Depreciation, depletion and impairment — The +following table summarizes depreciation, depletion and +impairment expense for 2007, 2006 and 2005 (in millions): +2007 +2006 +2005 +Depreciation and impairment expense +$ +234.7 +$ +186.6 +$ +146.1 +Depletion expense +14.5 +9.8 +10.3 +Total +$ +249.2 +$ +196.4 +$ +156.4 +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Retirements — Upon disposition or retirement of +property and equipment, the cost and related accumulated +depreciation are removed and any resulting gain or loss is +reflected in the consolidated statement of income. +Net income per common share — The Company +provides a dual presentation of its net income per common share +in its Consolidated Statements of Income: Basic net income per +common share (“Basic EPS”) and diluted net +F-8 +Table of Contents +income per common share (“Diluted EPS”). Basic EPS +excludes dilution and is computed by dividing net income by the +weighted average number of common shares outstanding during the +period excluding nonvested restricted stock. Diluted EPS is +based on the weighted-average number of common shares +outstanding plus the impact of dilutive instruments, including +stock options, warrants and restricted stock using the treasury +stock method. The following table presents information necessary +to calculate net income per share for the years ended +December 31, 2007, 2006 and 2005 as well as potentially +dilutive securities excluded from the weighted average number of +diluted common shares outstanding, as their inclusion would have +been anti-dilutive (in thousands, except per share amounts): +2007 +2006 +2005 +Net income +$ +438,639 +$ +673,254 +$ +372,740 +Weighted average number of common shares outstanding excluding +nonvested restricted stock +154,755 +165,159 +170,426 +Basic net income per common share +$ +2.83 +$ +4.08 +$ +2.19 +Weighted average number of common shares outstanding excluding +nonvested restricted stock +154,755 +165,159 +170,426 +Dilutive effect of stock options and restricted shares +2,242 +2,254 +3,341 +Weighted average number of diluted common shares outstanding +156,997 +167,413 +173,767 +Diluted net income per common share +$ +2.79 +$ +4.02 +$ +2.15 +Potentially dilutive securities excluded as anti-dilutive +2,460 +800 +— +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. +The Company adopted FASB Interpretation No. 48, +Accounting for Uncertainty in Income Taxes — an +interpretation of FASB Statement No. 109 +(“FIN 48”) on January 1, 2007. +FIN 48 clarifies the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribes a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of FIN 48 the Company reduced a +reserve for an uncertain tax position with respect to a business +combination that had originally been recorded as goodwill (see +Note 5). The impact of adjustments to reserves with respect +to other uncertain tax positions was not material. In connection +with the adoption of FIN 48, the Company established a +policy to account for interest and penalties with respect to +income taxes as operating expenses. +Stock based compensation — Prior to +January 1, 2006, the Company accounted for stock based +compensation related to employee stock options and shares of +restricted stock using the recognition and measurement +principles of APB Opinion No. 25, Accounting for Stock +Issued to Employees (“APB 25”), and related +interpretations. Under the provisions of APB 25, expense +associated with stock option grants was measured based on the +intrinsic value of the option at the date of grant and expense +associated with restricted stock grants was measured based on +the fair value of the shares at the date of grant. Reductions in +compensation expense associated with awards that were forfeited +prior to vesting were recognized as those grants were forfeited. +Effective January 1, 2006, the Company adopted the +provisions of Financial Accounting Standards Board Statement +No. 123(R), Share-Based Payment +(“SFAS 123(R)”). SFAS 123(R) requires +the recognition of expense associated with the grant of both +stock options and restricted stock based on the estimated fair +value of the options or restricted stock at the date of grant, +net of estimated forfeitures. +F-9 +Table of Contents +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Recently Issued Accounting Standards — In +September 2006, the FASB issued Statement No. 157, Fair +Value Measurements (“FAS 157”). FAS 157 +defines fair value, establishes a framework for measuring fair +value in generally accepted accounting principles, and expands +disclosures about fair value measurement. FAS 157 is +effective for financial statements issued for fiscal years +beginning after November 15, 2007 and interim periods +within those fiscal years. FAS 157 will be effective for +the Company beginning in the quarter ending March 31, 2008. +The application of FAS 157 is not expected to have a +material impact to the Company. +In February 2007, the FASB issued Statement No. 159, The +Fair Value Option for Financial Assets and Financial Liabilities +Including an Amendment of FASB Statement No. 115 +(“FAS 159”). FAS 159 permits entities to +choose to measure many financial instruments and certain other +items at fair value. FAS 159 is effective as of the +beginning of an entity’s first fiscal year that begins +after November 15, 2007 and will be effective for the +Company beginning in the quarter ending March 31, 2008. The +application of FAS 159 is not expected to have a material +impact to the Company. +In December 2007, the FASB issued Statement No. 141(R), +Business Combinations (“FAS 141(R)”) and +Statement No. 160, Noncontrolling Interests in +Consolidated Financial Statements, an amendment of ARB +No. 51 (“FAS 160”). FAS 141(R) is a +revision of Statement No. 141, Business +Combinations , and calls for significant changes from current +practice in accounting for business combinations. +FAS 141(R) is effective for business combinations for which +the acquisition date is on or after the beginning of the first +annual reporting period beginning on or after December 15, +2008. FAS 160 amends ARB 51 to establish accounting and +reporting standards for the noncontrolling interest in a +subsidiary and for the deconsolidation of a subsidiary. +FAS 160 is effective for fiscal years beginning on or after +December 15, 2008. Both FAS 141(R) and FAS 160 +will be effective for the Company beginning the quarter ending +March 31, 2009. The application of FAS 141(R) and +FAS 160 are not expected to have a material impact to the +Company. +Reclassifications — Certain reclassifications +have been made to the 2006 and 2005 consolidated financial +statements in order for them to conform with the 2007 +presentation. +2. +Acquisitions +2007 +Acquisitions +On October 9, 2007, the Company acquired three recently +refurbished SCR electric land-based drilling rigs and spare +drilling equipment for $29.0 million. 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. +2005 +Acquisitions +Key Energy Services, Inc. — On January 15, +2005, the Company purchased land drilling assets from Key Energy +Services, Inc. for $61.8 million. The assets included 25 +active and 10 stacked land-based drilling rigs, related drilling +equipment, yard facilities and a rig moving fleet consisting of +approximately 45 trucks and 100 trailers. The transaction +was accounted for as an acquisition of assets and the purchase +price was allocated among the assets acquired based on their +estimated fair market values. +Other — On June 17, 2005, the Company +acquired one land-based drilling rig for $3.6 million and +on September 29, 2005, the Company acquired five land-based +drilling rigs and related drilling equipment for +$8.2 million. The transactions were accounted for as +acquisitions of assets and the purchase price was allocated +among the assets acquired based on their estimated fair market +values. +F-10 +Table of Contents +3. +Comprehensive +Income +The following table illustrates the Company’s comprehensive +income including the effects of foreign currency translation +adjustments for the years ended December 31, 2007, 2006 and +2005 (in thousands): +2007 +2006 +2005 +Net income +$ +438,639 +$ +673,254 +$ +372,740 +Other comprehensive income: +Foreign currency translation adjustment related to Canadian +operations, net of tax +11,817 +(175 +) +1,215 +Comprehensive income +$ +450,456 +$ +673,079 +$ +373,955 +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2007 and 2006 (in thousands): +2007 +2006 +Equipment +$ +2,748,007 +$ +2,135,567 +Oil and natural gas properties +75,732 +85,143 +Buildings +50,955 +30,987 +Land +9,991 +7,507 +2,884,685 +2,259,204 +Less accumulated depreciation and depletion +(1,043,281 +) +(823,400 +) +$ +1,841,404 +$ +1,435,804 +5. +Goodwill +Goodwill is evaluated at least annually to determine if the fair +value of recorded goodwill has decreased below its carrying +value. At December 31, 2007 the Company performed its +annual goodwill evaluation and determined no adjustment to +impair goodwill was necessary. For purposes of impairment +testing, goodwill is evaluated at the reporting unit level. The +Company’s reporting units for impairment testing have been +determined to be its operating segments. Goodwill by operating +segment as of December 31, 2007 and 2006 and changes for +the years then ended are as follows (in thousands): +2007 +2006 +Contract Drilling: +Goodwill at beginning of year +$ +89,092 +$ +89,092 +Changes to goodwill +(2,858 +) +— +Goodwill at end of period +86,234 +89,092 +Drilling and completion fluids: +Goodwill at beginning of year +9,964 +9,964 +Changes to goodwill +— +— +Goodwill at end of period +9,964 +9,964 +Total goodwill +$ +96,198 +$ +99,056 +In connection with the implementation of FIN 48 as of +January 1, 2007 as discussed in Note 1 of these +Consolidated Financial Statements, the Company determined that a +tax reserve of $2.9 million which had been established in +connection with a business acquisition should be reduced to +zero. This reserve had originally been established in connection +with the allocation of the purchase price in the transaction and +was reflected as an increase in goodwill. +F-11 +Table of Contents +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2007 and 2006 (in thousands): +2007 +2006 +Salaries, wages, payroll taxes and benefits +$ +33,816 +$ +42,751 +Workers’ compensation liability +70,989 +69,330 +Sales, use and other taxes +12,119 +11,043 +Insurance, other than workers’ compensation +16,308 +13,328 +Other +3,602 +9,011 +$ +136,834 +$ +145,463 +7. +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 2007 and 2006 +(in thousands): +2007 +2006 +Balance at beginning of year +$ +1,829 +$ +1,725 +Liabilities incurred +276 +154 +Liabilities settled +(862 +) +(104 +) +Accretion expense +61 +54 +Revision in estimated costs of plugging oil and natural gas wells +289 +— +Asset retirement obligation at end of year +$ +1,593 +$ +1,829 +8. +Borrowings +Under Line of Credit +The Company has an unsecured revolving line of credit +(“LOC”) with a maximum borrowing capacity of +$375 million. Interest is paid on outstanding LOC balances +at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the +prime rate. Any outstanding borrowings must be repaid at +maturity on December 16, 2009. This arrangement includes +various fees, including a commitment fee on the average daily +unused amount (0.15% at December 31, 2007). There are +customary restrictions and covenants associated with the LOC. +Financial covenants provide for a maximum debt to capitalization +ratio and a minimum interest coverage ratio. The Company does +not expect that the restrictions and covenants will restrict its +ability to operate or react to opportunities that might arise. +As of December 31, 2007, the Company had outstanding +borrowings of $50.0 million under the LOC and +$59.4 million in letters of credit were outstanding. As a +result, the Company had available borrowing capacity of +$266 million at December 31, 2007. The weighted +average interest rate on borrowings outstanding at +December 31, 2007 was 5.47%. The carrying value of +borrowings outstanding under the LOC approximates fair value due +to the floating interest rate. +9. +Commitments, +Contingencies and Other Matters +Commitments — The Company maintains letters of +credit in the aggregate amount of $59.4 million for the +benefit of various insurance companies as collateral for +retrospective premiums and retained losses which may become +payable under the terms of the underlying insurance contracts. +These letters of credit are typically renewed annually. No +amounts have been drawn under the letters of credit. +As of December 31, 2007, the Company has non-cancelable +commitments to purchase approximately $83.0 million of +equipment. +Contingencies — The Company’s contract +services and oil and natural gas exploration and production +operations are subject to inherent risks, including blowouts, +cratering, fire and explosions which could result in +F-12 +Table of Contents +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 $100 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. +The Company believes it is adequately insured for public +liability and property damage to others with respect to its +operations. However, such insurance may not be sufficient to +protect the Company against liability for all consequences of +well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its rigs. However, it does not +cover the full replacement cost of the rigs and the Company does +not carry insurance against loss of earnings resulting from such +damage. There can be no assurance that such insurance coverage +will always be available on terms that are satisfactory to the +Company. +In November 2005, the Company discovered that its former Chief +Financial Officer, Jonathan D. Nelson (“Nelson”), had +fraudulently diverted approximately $77.5 million in +Company funds for his own benefit. As a result, the Audit +Committee of the Board of Directors commenced an investigation +into Nelson’s activities and retained independent counsel +and independent forensic accountants to assist with the +investigation. Nelson has been sentenced and is serving a term +of imprisonment arising out of his embezzlement. A receiver was +appointed to take control of and liquidate the assets of Nelson. +In May 2007, the court approved a plan of distribution for the +assets recovered by the receiver. The Company expects to recover +a total of approximately $44.5 million pursuant to the +approved plan, and has recognized this recovery in the +Company’s consolidated statement of income in 2007, net of +professional fees incurred as a result of the embezzlement. As +of December 31, 2007, the Company had received cash +payments from the receiver of approximately $41.2 million, +with the remaining $3.3 million of the expected recovery +consisting of notes receivable, investments and other assets +that have been or are expected to be transferred to the Company. +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic twelve +month renewals unless the Company notifies the Key Employee at +least ninety days before the end of such renewal period that the +term will not be extended. If a change in control of the Company +occurs during the term of the agreement and the Key +Employee’s employment is terminated (i) by the Company +other than for cause or other than automatically as a result of +death, disability or retirement or (ii) by the Key Employee +for good reason (as those terms are defined in the Change in +Control Agreements), then the Key Employee shall generally be +entitled to, among other things, +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +F-13 +Table of Contents +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +10. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2007, 2006 +and 2005 as follows: +Per Share +Total +(In thousands) +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends declared and paid +$ +0.44 +$ +68,561 +2006: +Paid on March 30, 2006 +$ +0.04 +$ +6,906 +Paid on June 30, 2006 +0.08 +13,413 +Paid on September 29, 2006 +0.08 +13,024 +Paid on December 29, 2006 +0.08 +12,482 +Total cash dividends declared and paid +$ +0.28 +$ +45,825 +2005: +Paid on March 4, 2005 +$ +0.04 +$ +6,746 +Paid on June 1, 2005 +0.04 +6,790 +Paid on September 1, 2005 +0.04 +6,904 +Paid on December 1, 2005 +0.04 +6,899 +Total cash dividends declared and paid +$ +0.16 +$ +27,339 +On February 13, 2008, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.12 per share to be paid on March 28, 2008 to holders of +record as of March 12, 2008. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +The Company has granted restricted shares of the Company’s +common stock (“Restricted Shares”) to certain +employees under the Patterson-UTI Energy, Inc. 1997 Long-Term +Incentive Plan, as amended, and the Patterson-UTI Energy, Inc. +2005 Long-Term Incentive Plan. As required by SFAS 123(R), +the Restricted Shares were valued based upon the market price of +the Company’s common stock on the date of the grant. The +restrictions on these shares lapse at various dates through 2010. +On June 7, 2004, the Company’s Board of Directors +authorized a stock buyback program (“2004 Program”) +for the purchase of up to $30 million of the Company’s +outstanding common stock in open market or privately negotiated +transactions. During 2004, the Company purchased +100,000 shares of its common stock under the 2004 Program +in the open market for approximately $1.5 million. During +2005, the Company purchased 355,000 shares of its common +stock under the 2004 Program in the open market for +approximately $12.2 million. On March 27, 2006, the +Company’s Board of Directors increased the 2004 Program to +allow for future purchases of up to $200 million of the +Company’s outstanding common stock. During the second +quarter of 2006, the Company completed the purchase of +6,704,800 shares of its common stock under the 2004 Program +in the open market at a cost of approximately $200 million. +On August 2, 2006, the Company’s Board of Directors +again increased the 2004 +F-14 +Table of Contents +Program to allow for future purchases of up to $250 million +of the Company’s outstanding common stock. During the +remainder of 2006, the Company purchased an additional +9,940,542 shares of its common stock under the 2004 Program +in the open market at a cost of approximately $250 million. +On August 1, 2007, the Company’s Board of Directors +approved a new stock buyback program (“2007 Program”), +authorizing purchases of up to $250 million of the +Company’s common stock in open market or privately +negotiated transactions. During the year ended December 31, +2007, the Company purchased 3,308,850 shares of its common +stock under the 2007 Program at a cost of approximately +$70.4 million. As of December 31, 2007, the Company is +authorized to purchase approximately $180 million of the +Company’s outstanding common stock under the 2007 Program. +Shares purchased under the 2004 and 2007 stock buyback programs +have been accounted for as treasury stock. +Additionally, the Company purchased 20,269 shares of +treasury stock from employees during 2007. These shares were +purchased at fair market value upon the vesting of restricted +stock to provide the employees with the funds necessary to +satisfy their respective tax withholding obligations. The total +purchase price for these shares was approximately $496,000. +11. +Stock-based +Compensation +The Company adopted FASB 123(R) on January 1, 2006 and +recognizes the cost of share-based payments under the +fair-value-based method. The Company uses share-based payments +to compensate employees and non-employee directors. All awards +have been equity instruments in the form of stock options or +restricted stock awards and have included both service and +performance conditions. The Company issues shares of common +stock when vested stock option awards are exercised and when +restricted stock awards are granted. For the year ended +December 31, 2007, the Company recognized +$19.4 million in stock-based compensation expense and a +related income tax benefit of approximately $6.7 million. +For the year ended December 31, 2006, the Company +recognized $16.3 million in stock-based compensation +expense and a related income tax benefit of approximately +$5.8 million and recognized a benefit in the form of a +cumulative effect of change in accounting principle associated +with the adoption of FAS 123(R) of $1.1 million, with +a related tax expense of $398,000. +During 2005, the Company’s shareholders approved the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the +“2005 Plan”) and the Board of Directors adopted a +resolution that no future grants would be made under any of the +Company’s other previously existing plans. The +Company’s share-based compensation plans at +December 31, 2007 follow: +Options & +Shares +Restricted +Shares +Authorized +Shares +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan +6,250,000 +3,079,250 +2,283,045 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +4,903,337 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +669,747 +— +Amended and Restated Non-Employee Director Stock Option Plan of +Patterson-UTI Energy, Inc. (“Non-Employee Director +Plan”) +— +120,000 +— +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (“1996 Plan”) +— +81,600 +— +Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as +amended (“1993 Plan”) +— +39,300 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +F-15 +Table of Contents +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over 1 year for non-employee +directors and 3 to 4 years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2007, only +non-incentive stock options and restricted stock awards had been +granted under the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted Stock +Awards granted under the 1997 Plan typically vest over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Options granted under the Non-Employee Director Plan vest on the +first anniversary of the option grant and have a term of five +years. All options were granted with an exercise price equal to +the fair market value of the related common stock at the time of +grant. +Options granted under the 1996 plan typically vest over one, +four or five years as dictated by the Compensation Committee. +These options have terms of no more than 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. +Options granted under the 1993 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Stock Options — The Company accounted for all +stock options under the intrinsic value method prior to +January 1, 2006. Accordingly, no compensation expense was +recognized in periods prior to 2006 for stock options because +they had no intrinsic value when granted as exercise prices were +equal to the grant date market value of the related common +stock. The Modified Prospective Application (“MPA”) +method was applied to transition from the intrinsic value method +to the fair-value-based method for stock options. The effects of +the application of the MPA method follow: +• +Previously reported amounts and disclosures are not affected. +• +Compensation cost, net of estimated forfeitures for the unvested +portion of awards outstanding at January 1, 2006, is +recognized under the fair-value-based method as the awards vest. +Compensation cost is based on the grant-date estimated fair +value of stock options as calculated for the Company’s +previously reported pro forma disclosures under FASB Statement +No. 123, Accounting for Stock-Based Compensation +(“FAS 123”). +• +The fair-value based method is applied to new awards and to any +awards outstanding at January 1, 2006 that are modified, +repurchased or cancelled after that date. +F-16 +Table of Contents +The Company estimates grant date fair values of stock options +using the Black-Scholes-Merton valuation model +(“Black-Scholes”), except for stock options granted +prior to 1996 that are not subject to FAS 123(R) and were +not subject to FAS 123 pro forma disclosures. Volatility +assumptions are based on the historic volatility of the +Company’s common stock over the most recent period equal to +the expected term of the options as of the date the options were +granted. The expected term assumptions are based on the +Company’s experience with respect to employee stock option +activity. Dividend yield assumptions are based on the expected +dividends at the time the options were granted. The risk-free +interest rate assumptions are determined by reference to United +States Treasury yields. Weighted-average assumptions used to +estimate grant date fair values for stock options granted in the +years ended December 31, 2007, 2006 and 2005 follow: +2007 +2006 +2005 +Volatility +36.37 +% +33.18 +% +26.95 +% +Expected term (in years) +4.00 +4.00 +4.00 +Dividend yield +1.97 +% +1.09 +% +0.65 +% +Risk-free interest rate +4.55 +% +4.87 +% +3.84 +% +Stock option activity for the year ended December 31, 2007 +follows: +Weighted- +Average +Exercise +Shares +Price +Outstanding at beginning of year +6,575,096 +$ +16.18 +Granted +1,060,000 +$ +23.92 +Exercised +(229,812 +) +$ +8.92 +Forfeited +(2,183 +) +$ +14.64 +Expired +(17 +) +$ +14.64 +Outstanding at end of year +7,403,084 +$ +17.52 +Exercisable at end of year +5,879,750 +$ +15.54 +Options outstanding at December 31, 2007 have an aggregate +intrinsic value of approximately $29.8 million and a +weighted-average remaining contractual term of 5.9 years. +Options exercisable at December 31, 2007 have an aggregate +intrinsic value of approximately $29.8 million and a +weighted-average remaining contractual term of 5.1 years. +Additional information with respect to options granted, vested +and exercised during the years ended December 31, 2007, +2006 and 2005 follows: +2007 +2006 +2005 +Weighted-average grant-date fair value of stock options granted +(per share) +$ +7.09 +$ +8.62 +$ +6.33 +Grant-date fair value of stock options vested during the year +(in thousands) +$ +5,613 +$ +6,900 +$ +15,738 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +3,186 +$ +3,377 +$ +73,467 +As of December 31, 2007, options to purchase +1,523,334 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2007 with respect +to these options that are expected to vest follows: +Aggregate intrinsic value +$ +0 +Weighted-average remaining contractual term +9.03 years +Weighted-average remaining expected term +3.03 years +Weighted-average remaining vesting period +1.97 years +Unrecognized compensation cost +$ +9.3 million +F-17 +Table of Contents +Restricted Stock — Under all restricted stock +awards to date, shares were issued when granted, nonvested +shares are subject to forfeiture for failure to fulfill service +conditions and, in certain cases, performance conditions. +Nonforfeitable dividends are paid on nonvested restricted +shares. Restricted stock awards prior to January 1, 2006 +were valued at the grant date market value of the underlying +common stock, recognized as contra equity deferred compensation +and amortized to expense under the “graded-vesting” +method. Implementation of FAS 123(R) did not change the +accounting for the Company’s nonvested stock awards, except +as follows: +• +Prior to January 1, 2006, forfeitures were recognized as +they occurred; +• +From January 1, 2006 forward, forfeitures are estimated in +the determination of periodic compensation cost; +• +Contra equity deferred compensation was reversed against +paid-in-capital +at January 1, 2006; and +• +Compensation expense is recognized as attributed to each period. +The Company uses the “graded-vesting” attribution +method to determine periodic compensation cost from restricted +stock awards. +Restricted stock activity for the year ended December 31, +2007 follows: +Weighted- +Average Grant +Shares +Date Fair Value +Nonvested restricted stock outstanding at beginning of year +1,188,200 +$ +25.92 +Granted +601,150 +$ +24.60 +Vested +(197,645 +) +$ +19.37 +Forfeited +(101,555 +) +$ +26.51 +Nonvested restricted stock outstanding at end of year +1,490,150 +$ +26.22 +As of December 31, 2007, approximately +1,440,000 shares of nonvested restricted stock outstanding +are expected to vest. Additional information as of +December 31, 2007 with respect to these shares that are +expected to vest follows: +Aggregate intrinsic value +$28.1 million +Weighted-average remaining vesting period +1.97 years +Unrecognized compensation cost +$16.5 million +Dividends on Equity Awards — Nonforfeitable +dividends paid on equity awards are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of equity awards expected to vest. +• +Dividends are recognized as additional compensation cost for the +portion of equity awards that are not expected to vest or that +ultimately do not vest. +Vesting expectations, in regard to these dividend payments, +correspond with forfeiture assumptions used to recognize +compensation cost. +F-18 +Table of Contents +Prior Period Pro Forma Disclosures — Prior to +January 1, 2006, the Company accounted for share-based +compensation under the intrinsic value method. Other than the +restricted stock discussed above, no additional share-based +compensation expense was reflected in earnings prior to +January 1, 2006 since the exercise price was equal to the +grant-date market value of the underlying common stock for all +stock options granted prior to that date. The effect of +share-based compensation, as if the Company had applied the +fair-value-based method proscribed by FAS 123, on net +income and earnings per share for the year ended +December 31, 2005 is as follows (in thousands, except per +share amounts): +2005 +Net income, as reported +$ +372,740 +Add back: Share-based employee compensation cost, net of related +tax effects, included in net income as reported +1,795 +Deduct: Share-based employee compensation cost, net of related +tax effects, that would have been included in net income if the +fair-value-based method had been applied to all awards +(11,119 +) +Pro-forma net income +$ +363,416 +Net income per common share: +Basic, as reported +$ +2.19 +Basic, pro-forma +$ +2.13 +Diluted, as reported +$ +2.15 +Diluted, pro-forma +$ +2.11 +12. +Leases +The Company incurred rent expense of $33.9 million, +$31.8 million and $22.5 million, for the years 2007, +2006 and 2005, respectively. Rent expense is primarily related +to short-term equipment rentals that are passed through to +customers. The Company’s obligations under non-cancelable +operating lease agreements are not material to the +Company’s operations or cash flows. +13. +Income +Taxes +The Company adopted FASB Interpretation No. 48, +Accounting for Uncertainty in Income Taxes — an +interpretation of FASB Statement No. 109 +(“FIN 48”), on January 1, 2007. +FIN 48 clarifies the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribes a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of FIN 48 the Company reduced a +reserve that had been established for an uncertain tax position +that was taken with respect to a business combination. The +reserve had originally been recorded as goodwill (see +Note 5). The impact of adjustments to reserves with respect +to other uncertain tax positions was not material. As of +December 31, 2007, the Company had no unrecognized tax +benefits. In connection with the adoption of FIN 48, the +Company established a policy to account for interest and +penalties related to uncertain income tax positions as operating +expenses. As of December 31, 2007, the tax years ended +December 31, 2004 through December 31, 2006 are open +for examination by U.S. taxing authorities. As of +December 31, 2007, the tax years ended December 31, +2003 through December 31, 2006 are open for examination by +Canadian taxing authorities. +F-19 +Table of Contents +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2007, 2006 and 2005 are as follows (in +thousands): +2007 +2006 +2005 +Federal income tax expense (benefit): +Current +$ +172,221 +$ +344,395 +$ +174,635 +Deferred +36,864 +(5,851 +) +14,182 +209,085 +338,544 +188,817 +State income tax expense: +Current +16,456 +21,371 +13,045 +Deferred +983 +1,392 +1,431 +17,439 +22,763 +14,476 +Foreign income tax expense: +Current +5,220 +9,607 +7,238 +Deferred +424 +353 +1,488 +5,644 +9,960 +8,726 +Total: +Current +193,897 +375,373 +194,918 +Deferred +38,271 +(4,106 +) +17,101 +Total income tax expense +$ +232,168 +$ +371,267 +$ +212,019 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2007, 2006 and 2005 is summarized as follows: +2007 +2006 +2005 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.4 +1.4 +1.8 +Permanent differences +(1.6 +) +(0.8 +) +(0.6 +) +Other, net +(0.2 +) +0.0 +0.1 +Effective tax rate +34.6 +% +35.6 +% +36.3 +% +F-20 +Table of Contents +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December +December +December +December +31, +Net +31, +Net +31, +Net +31, +2007 +Change +2006 +Change +2005 +Change +2004 +Deferred tax assets: +Current: +Federal net operating loss carryforwards +$ +374 +$ +(1,496 +) +$ +1,870 +$ +— +$ +1,870 +$ +— +$ +1,870 +Workers’ compensation allowance +26,586 +223 +26,363 +6,902 +19,461 +4,584 +14,877 +Embezzlement costs +660 +(13,634 +) +14,294 +14,294 +— +— +— +Other +18,404 +3,903 +14,501 +3,137 +11,364 +4,386 +6,978 +46,024 +(11,004 +) +57,028 +24,333 +32,695 +8,970 +23,725 +Non-current: +Federal net operating loss carryforwards +— +(374 +) +374 +(1,871 +) +2,245 +(1,870 +) +4,115 +AMT credit +118 +— +118 +— +118 +— +118 +Federal benefit of foreign deferred tax liabilities +8,973 +424 +8,549 +353 +8,196 +1,488 +6,708 +Federal benefit of state deferred tax liabilities +5,427 +735 +4,692 +460 +4,232 +717 +3,515 +Embezzlement costs +— +— +— +— +— +(22,178 +) +22,178 +Other +9,999 +2,890 +7,109 +6,172 +937 +174 +763 +24,517 +3,675 +20,842 +5,114 +15,728 +(21,669 +) +37,397 +Total deferred tax assets +70,541 +(7,329 +) +77,870 +29,447 +48,423 +(12,699 +) +61,122 +Deferred tax liabilities: +Current: +Other +(10,654 +) +(2,492 +) +(8,161 +) +(1,848 +) +(6,313 +) +1,421 +(7,734 +) +Non-current: +Property and equipment basis difference +(231,965 +) +(28,466 +) +(203,500 +) +(23,775 +) +(179,725 +) +(6,381 +) +(173,344 +) +Other +(12,042 +) +(6,741 +) +(5,301 +) +(110 +) +(5,191 +) +(663 +) +(4,528 +) +(244,007 +) +(35,207 +) +(208,801 +) +(23,885 +) +(184,916 +) +(7,044 +) +(177,872 +) +Total deferred tax liabilities +(254,661 +) +(37,699 +) +(216,962 +) +(25,733 +) +(191,229 +) +(5,623 +) +(185,606 +) +Net deferred tax liability +$ +(184,120 +) +$ +(45,028 +) +$ +(139,092 +) +$ +3,714 +$ +(142,806 +) +$ +(18,322 +) +$ +(124,484 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2007 to be +realized as a result of the reversal during the carryforward +period of existing taxable temporary differences giving rise to +deferred tax liabilities and the generation of taxable income in +the carryforward period; therefore, no valuation allowance is +necessary. +Management deducted accumulated net embezzlement losses in the +Company’s 2005 tax returns, which corresponds with the +period in which the embezzlement was detected. +F-21 +Table of Contents +Other deferred tax assets consist primarily of various allowance +accounts and tax deferred expenses expected to generate future +tax benefit of approximately $28 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 Federal net operating loss +carryforwards of approximately $374,000 available at +December 31, 2007. The Company has alternative minimum tax +credit carryforwards of approximately $118,000 available at +December 31, 2007. The net operating loss carryforwards, if +unused, are scheduled to expire in 2019. The alternative minimum +tax credit may be carried forward indefinitely. +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $4.2 million in 2007, $3.1 million in +2006 and $2.7 million in 2005 for the Company’s +contributions to the plan. +15. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to four business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services, (iii) drilling and +completion fluids services to operators in the oil and natural +gas industry, and (iv) the exploration, development, +acquisition and production of oil and natural gas. Each of these +segments represents a distinct type of business based upon the +type and nature of services and products offered. These segments +have separate management teams which report to the +Company’s chief operating decision maker and have distinct +and identifiable revenues and expenses. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2007, the Company +had 350 currently marketable land-based drilling rigs, of which +107 of the drilling rigs were based in the Permian Basin region, +51 in South Texas, 42 in the Ark-La-Tex region and Mississippi, +75 in the Mid-Continent region, 52 in the Rocky Mountain region, +3 in the Appalachian Basin and 20 in Western Canada. +Pressure Pumping — The Company provides +pressure pumping services primarily in the Appalachian Basin. +Pressure pumping services consist primarily of well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Well stimulation involves processes inside a +well designed to enhance the flow of oil, natural gas, or other +desired substances from the well. Cementing is the process of +inserting material between the hole and the pipe to center and +stabilize the pipe in the hole. +Drilling and Completion Fluids — The Company +provides drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast region of Louisiana. Drilling and completion fluids +are used by oil and natural gas operators during the drilling +process to control pressure when drilling oil and natural gas +wells. +Oil and Natural Gas — The Company has been +engaged in the development, exploration, acquisition and +production of oil and natural gas. Through October 31, +2007, the Company served as operator with respect to several +properties and was actively involved in the development, +exploration, acquisition and production of oil and natural gas. +Effective November 1, 2007 the Company sold the related +operations portion of its exploration and production business. +The Company continues to own and invest in oil and natural gas +assets as a working interest owner. The Company’s oil and +natural gas interest are located primarily in producing regions +of West and south Texas, Southeastern New Mexico, Utah and +Mississippi. +F-22 +Table of Contents +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2007 +2006 +2005 +Revenues: +Contract drilling(a) +$ +1,744,884 +$ +2,174,805 +$ +1,488,485 +Pressure pumping +202,812 +145,671 +93,144 +Drilling and completion fluids(b) +128,447 +192,974 +122,309 +Oil and natural gas +41,637 +39,187 +39,616 +Total segment revenues +2,117,780 +2,552,637 +1,743,554 +Elimination of intercompany revenues(a)(b) +(3,586 +) +(6,051 +) +(3,099 +) +Total revenues +$ +2,114,194 +$ +2,546,586 +$ +1,740,455 +Income before income taxes: +Contract drilling +$ +558,792 +$ +991,449 +$ +572,562 +Pressure pumping +64,257 +44,835 +21,664 +Drilling and completion fluids +6,528 +28,759 +12,201 +Oil and natural gas +10,998 +8,660 +13,405 +640,575 +1,073,703 +619,832 +Corporate and other +(30,799 +) +(27,639 +) +(19,724 +) +Embezzlement (costs) recoveries(c) +43,955 +(3,081 +) +(20,043 +) +Gain (loss) on disposal of assets(d) +16,545 +(3,819 +) +1,231 +Interest income +2,355 +5,925 +3,551 +Interest expense +(2,187 +) +(1,602 +) +(516 +) +Other +363 +347 +428 +Income before income taxes +$ +670,807 +$ +1,043,834 +$ +584,759 +Identifiable assets: +Contract drilling +$ +2,132,910 +$ +1,849,923 +$ +1,421,779 +Pressure pumping +154,120 +111,787 +72,536 +Drilling and completion fluids +91,989 +106,032 +90,904 +Oil and natural gas +37,885 +65,443 +60,785 +Corporate and other(e) +48,295 +59,318 +149,777 +Total assets +$ +2,465,199 +$ +2,192,503 +$ +1,795,781 +Depreciation, depletion and impairment: +Contract drilling +$ +213,812 +$ +168,607 +$ +131,740 +Pressure pumping +14,311 +9,896 +7,094 +Drilling and completion fluids +2,860 +2,706 +2,368 +Oil and natural gas +17,410 +14,368 +14,456 +Corporate and other +813 +793 +735 +Total depreciation, depletion and impairment +$ +249,206 +$ +196,370 +$ +156,393 +Capital expenditures: +Contract drilling +$ +539,506 +$ +531,087 +$ +329,073 +Pressure pumping +47,582 +41,262 +25,508 +Drilling and completion fluids +3,082 +4,222 +3,042 +Oil and natural gas +17,516 +21,198 +17,163 +Corporate and other +— +150 +5,308 +Total capital expenditures +$ +607,686 +$ +597,919 +$ +380,094 +(a) +Includes contract drilling intercompany revenues of +approximately $3.2 million, $5.4 million and +$2.8 million for the years ended December 31, 2007, +2006 and 2005, respectively. +(b) +Includes drilling and completion fluids intercompany revenues of +approximately $348,000, $616,000 and $298,000 for the years +ended December 31, 2007, 2006 and 2005, respectively. +F-23 +Table of Contents +(c) +The Company’s former CFO has pleaded guilty to criminal +charges and has been sentenced and is serving a term of +imprisonment arising out of his embezzlement of funds from the +Company. Embezzlement costs in 2005 and 2006 include embezzled +funds and other costs incurred as a result of the embezzlement. +The Company expects to recover a total of approximately +$44.5 million in assets seized by a court-appointed +receiver from the former CFO and companies that he controlled. +Cash payments from the receiver of approximately +$41.2 million have been received as of December 31, +2007, with the remaining $3.3 million of the expected +recovery consisting of notes receivable, investments and other +assets that have been or are expected to be transferred to the +Company. The embezzlement recovery in 2007 includes the +recognition of this recovery, net of professional and other +costs incurred as a result of the embezzlement. +(d) +Gains or losses associated with the disposal of assets relate to +decisions of the executive management group regarding corporate +strategy. Accordingly, the related gains or losses have been +separately presented and excluded from the results of specific +segments. +(e) +Corporate and other assets primarily include cash on hand +managed by the parent corporation and certain deferred Federal +income tax assets. +16. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2007 +Operating revenues +$ +547,101 +$ +522,558 +$ +524,002 +$ +520,533 +Operating income +179,725 +215,136 +144,100 +131,315 +Net income +115,801 +139,551 +98,181 +85,106 +Net income per common share: +Basic +$ +0.75 +$ +0.90 +$ +0.63 +$ +0.56 +Diluted +$ +0.73 +$ +0.88 +$ +0.62 +$ +0.55 +2006 +Operating revenues +$ +597,733 +$ +636,813 +$ +673,658 +$ +638,382 +Operating income +245,599 +268,913 +281,905 +242,747 +Net income +159,256 +171,690 +185,990 +156,318 +Net income per common share: +Basic +$ +0.93 +$ +1.02 +$ +1.14 +$ +0.99 +Diluted +$ +0.91 +$ +1.00 +$ +1.12 +$ +0.97 +17. +Concentrations +of Credit Risk +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit quality financial +institutions. At December 31, 2007 and 2006, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2007 +2006 +Deposits in FDIC and SIPC-insured institutions under $100,000 +$ +462 +$ +684 +Deposits in FDIC and SIPC-insured institutions over $100,000 +53,112 +21,859 +Deposits in Foreign Banks +6,282 +3,754 +59,856 +26,297 +Less outstanding checks and other reconciling items +(42,422 +) +(12,912 +) +Cash and cash equivalents +$ +17,434 +$ +13,385 +F-24 +Table of Contents +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2007, 2006, or 2005. The Company recognized +bad debt expense for 2007, 2006 and 2005 of $2.6 million, +$5.4 million and $1.2 million, respectively. +The carrying values of cash and cash equivalents and trade +receivables approximate fair value due to the short-term +maturity of these items. +18. +Related +Party Transactions +Joint Operation of Oil and Natural Gas +Properties — Through October 31, 2007, the +Company served as operator with respect to several properties +and was actively involved in the development, exploration, +acquisition and production of oil and natural gas. Effective +November 1, 2007, the Company sold the operations portion +of its exploration and production business. The Company +continues to own and invest in oil and natural gas assets as a +working interest owner. During the time that the Company served +as operator, it served as operator with respect to certain oil +and natural gas properties in which certain of its affiliated +persons have participated, either individually or through +entities they control. These participations have typically been +through working interests in prospects or properties originated +or acquired by Patterson Petroleum, LLC, a wholly owned +subsidiary of Patterson-UTI. +During the time that the Company served as operator, sales of +working interests to affiliated parties were made by +Patterson-UTI at its cost, comprised of Patterson-UTI’s +costs of acquiring and preparing the working interests for sale +plus a promote fee in some cases. These costs were paid by the +working interest owners on a pro rata basis based upon their +working interest ownership percentage. The price at which +working interests were sold to affiliated persons was the same +price at which working interests were sold to unaffiliated +persons except that in some cases the affiliated persons also +paid a promote fee. The affiliated persons received oil and +natural gas production revenue (net of royalty) of +$19.0 million, $15.8 million and $15.5 million +from these properties in 2007, 2006 and 2005, respectively. +These persons or entities in turn paid for joint operating costs +(including drilling and other development expenses) of +$9.2 million, $14.1 million and $9.5 million +incurred in 2007, 2006 and 2005, respectively. These activities +resulted in a payable to the affiliated persons of $0 and +approximately $1.5 million and a receivable from the +affiliated persons of $0 and approximately $1.6 million at +December 31, 2007 and 2006, respectively. +F-25 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND +QUALIFYING ACCOUNTS +Charged to +Costs and +Description +Beginning Balance +Expenses(1) +Deductions(2) +Ending Balance +(In thousands) +Year Ended December 31, 2007 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +7,484 +$ +2,550 +$ +20 +$ +10,014 +Year Ended December 31, 2006 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +2,199 +$ +5,400 +$ +115 +$ +7,484 +Year Ended December 31, 2005 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +1,909 +$ +1,231 +$ +941 +$ +2,199 +(1) +Net of recoveries. +(2) +Uncollectible accounts written off. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 19, 2008 +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 +February 19, 2008. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +Table of Contents +EXHIBIT INDEX +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as +amended (filed March 13, 1998 as Exhibit 10.1 to the +Company’s Registration Statement on +Form S-8 +(File +No. 333-47917) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock +Option Plan, as amended (filed November 4, 1997 as +Exhibit 10.1 to the Company’s Registration Statement +on +Form S-8 +(File +No. 333-39471) +and incorporated herein by reference).* +10 +.4 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.6 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.7 +Amended and Restated Patterson-UTI Energy, Inc. Non-Employee +Director Stock Option Plan(filed July 28, 2003 as +Exhibit 4.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.8 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.9 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.10 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed +August 9, 2004 as Exhibit 10.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.11 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed +August 9, 2004 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +Table of Contents +10 +.12 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed +August 9, 2004 as Exhibit 10.4 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.13 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and John E. Vollmer III +(filed August 9, 2004 as Exhibit 10.6 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.15 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.16 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.18 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.19 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +William L. Moll, Jr. and Gregory W. Pipkin (filed April 28, +2004 as Exhibit 10.11 to the Company’s Annual Report +on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.20 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and William L. Moll, Jr. (filed +November 5, 2007 as Exhibit 10.7 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +Table of Contents +10 +.27 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and William L. Moll, Jr., entered +into November 1, 2007 (filed November 5, 2007 as +Exhibit 10.12 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.28 +Credit Agreement dated as of December 17, 2004 among +Patterson-UTI Energy, Inc., as the Borrower, Bank of America, +N.A., as administrative agent, L/C Issuer and a Lender and the +other lenders and agents party thereto (filed on +December 23, 2004 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.29 +Commitment Increase and Joinder Agreement, dated as of +August 2, 2006, by and among Patterson-UTI Energy, Inc., +the guarantors party thereto, the lenders party thereto, and +Bank of America, N.A. as Administrative Agent, L/C Issuer and +Lender (filed August 21, 2006 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.30 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics +for Senior Financial Executives (filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/filing_metadata.csv b/raw/filings/0000889900/2007/0000950134-08-003007/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..6a065b12a204ce130a28fd8fe95cebe3fda38e0f --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2008-02-19,2007-12-31,2008-02-19T21:01:27.000Z,0000950134-08-003007,d54088e10vk.htm,FORM 10-K,1157430,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013408003007/d54088e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095013408003007/,2007,2007,1 diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/item1.txt b/raw/filings/0000889900/2007/0000950134-08-003007/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..6b4307025da29e444752b825b8ae0c5ca9ff78af --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/item1.txt @@ -0,0 +1,643 @@ +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the +United States Securities and Exchange Commission +(“SEC”). You may read and copy any materials we file +with the SEC at the SEC’s Public Reference Room at +100 F Street, NE, Washington, DC 20549. You may obtain +information on the operation of the Public Reference Room by +calling the SEC at +1-800-SEC-0330. +Overview +Based on publicly available information, we believe we are the +second largest operator 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, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, South Dakota, Pennsylvania and western Canada (Alberta, +British Columbia and Saskatchewan). +As of December 31, 2007, we had a drilling fleet that +consisted of 350 currently marketable land-based 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. A drilling rig is considered +currently marketable at a point in time if it is +1 +Table of Contents +operating or can be made ready to operate without significant +capital expenditures. We also have a substantial inventory of +drilling rig components and equipment. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, Southeastern New Mexico, Oklahoma and the +Gulf Coast region of Louisiana. Drilling and completion fluids +are used by oil and natural gas operators during the drilling +process to control pressure when drilling oil and natural gas +wells. We own and invest in oil and natural gas assets as a +working interest owner. Our oil and natural gas interests are +located primarily in producing regions of West and South Texas, +Southeastern New Mexico, Utah and Mississippi. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2007, 2006 +and 2005. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2007, we had 350 currently marketable +land-based drilling rigs which were based in the following +regions: +• +107 in the Permian Basin region (West Texas and Southeastern New +Mexico), +• +51 in South Texas, +• +42 in the Ark-La-Tex region and Mississippi, +• +75 in the Mid-Continent region (Oklahoma and North Central +Texas), +• +52 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana, North Dakota and South Dakota), +• +3 in the Appalachian Basin, and +• +20 in Western Canada (Alberta, British Columbia and +Saskatchewan). +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Sixty-nine of these drilling rigs are electric rigs and 281 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. We also have a substantial inventory of drilling rig +components and equipment which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year on an ongoing program to modify and +upgrade our drilling rigs to ensure that our drilling equipment +is competitive. We have spent $1.4 billion during the last +three years on capital expenditures to modify, upgrade and +maintain our drilling fleet. During fiscal years 2007, 2006 and +2005, we spent approximately $540 million, +$531 million and $329 million, respectively, on these +capital expenditures. +2 +Table of Contents +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. Our rigs are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Typically, the contracts are short-term to +drill a single well or a series of wells. 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 +long-term contracts in 2005 and 2006 and, to a lesser extent, in +2007. These long-term contracts provide for the use of drilling +rigs for fixed periods of time during which multiple wells are +drilled. During 2007, our average number of days to drill a well +(which includes moving to the drill site, rigging up and rigging +down) was approximately 21 days. We may continue to enter +into long-term contracts when considered beneficial 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. +Most drilling contracts are subject to termination by the +customer on short notice. We generally indemnify our customers +against claims by our employees and claims that might arise from +surface pollution caused by spills of fuel, lubricants and other +solvents within our control. The customers generally indemnify +us against claims that might arise from other surface and +subsurface pollution, except claims that might arise from our +gross negligence. Each drilling contract will contain the actual +terms setting forth our rights and obligations and those of the +particular customer. +The contracts provide for payment on a daywork, footage, or +turnkey basis, or a combination thereof. In each case, we +provide the rig and crews. Our bid for each contract depends +upon location, depth and anticipated complexity of the well, +on-site +drilling conditions, equipment to be used, estimated risks +involved, estimated duration of the job, availability of +drilling rigs and other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving, or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor assumes certain risks +associated with loss of the well from fire, blowouts and other +risks. Due to market conditions, we have entered into very few +footage contracts in recent years. +Turnkey +Contracts +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also assume +certain risks associated with drilling the well such as fires, +blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed scope of the work has +been +3 +Table of Contents +completed, which requires us to make larger up-front working +capital commitments prior to receiving payments under a turnkey +drilling contract. Under a turnkey contract, we have the +opportunity to improve our profits if the drilling process goes +as expected and there are no complications or time delays. +However, given the increased exposure we have under a turnkey +contract, profits can be significantly reduced and losses can be +incurred if complications or delays occur during the drilling +process. Turnkey contracts generally involve the highest degree +of risk among the three different types of drilling contracts: +daywork, footage and turnkey. Due to market conditions, we have +entered into very few turnkey contracts in recent years. +Revenues by Contract Type — Information +regarding our revenues by contract type for the last three years +follows: +Year Ended December 31, +Type of Revenues +2007 +2006 +2005 +Daywork +100 +% +100 +% +98 +% +Footage +0 +0 +1 +Turnkey +0 +0 +1 +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2007 +2006 +2005 +Average rigs operating(1) +244 +296 +276 +Number of rigs operated +338 +331 +307 +Number of wells drilled +4,237 +5,050 +4,594 +Number of operating days +89,095 +108,221 +100,591 +(1) +A rig is operating when it is drilling, being moved, assembled, +dismantled or otherwise earning revenue under contract. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to rigs that were +currently marketable as of December 31, 2007 to be as +follows: +Depth Rating (Ft.) +Mechanical +Electric +Total +5,000 to 7,999 +4 +— +4 +8,000 to 11,999 +74 +2 +76 +12,000 to 15,999 +186 +33 +219 +16,000 to 30,000 +17 +34 +51 +Totals +281 +69 +350 +At December 31, 2007, we owned and operated 324 trucks and +441 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and Western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the +4 +Table of Contents +well bore. Generally, Appalachian Basin wells require cementing +services before production commences. The cementing process +inserts material between the wall of the well bore and the +casing to center and stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2007 follows: +• +34 cement pumper trucks, +• +57 fracturing pumper trucks, +• +47 nitrogen pumper trucks, +• +26 blender trucks, +• +24 acid trucks, +• +46 bulk cement trucks, +• +19 bulk nitrogen trucks, +• +3 bulk nitrogen tractor trailer combinations, +• +51 bulk sand trucks, +• +14 sand pneumatic trucks, and +• +26 connection trucks. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +Southeastern New Mexico, Oklahoma and the Gulf Coast region of +Louisiana. We serve our offshore customers through six +stockpoint facilities located along the Gulf of Mexico in Texas +and Louisiana and our land-based customers through fourteen +stockpoint facilities in Texas, Louisiana, Oklahoma and New +Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to ensure that the products and systems are applied +effectively to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +Raw Materials — Our drilling and completion +fluids 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 — We operate a barite +grinding facility with two barite grinding mills in Houma, +Louisiana. This facility allows us to grind raw barite into the +powder additive used in drilling fluids. +Other Equipment — We own and operate 20 trucks +and 92 trailers and lease another 34 trucks which are used to +transport drilling and completion fluids and related equipment. +5 +Table of Contents +Oil and +Natural Gas Operations +General — We have been engaged in the +development, exploration, acquisition and production of oil and +natural gas. Through October 31, 2007, we served as +operator with respect to several properties and were actively +involved in the development, exploration, acquisition and +production of oil and natural gas. Effective November 1, +2007, we sold the related operations portion of our exploration +and production business. We continue to own and invest in oil +and natural gas assets as a working interest owner. Our oil and +natural gas interests are located primarily in producing regions +of West and South Texas, Southeastern New Mexico, Utah and +Mississippi. +Customers +The customers of each of our three oil service business segments +are oil and natural gas operators. Our customer base includes +both major and independent oil and natural gas operators. During +2007, no single customer accounted for 10% or more of our +consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping +Businesses — Our land drilling and pressure +pumping businesses are highly competitive. At times, available +land drilling rigs and pressure pumping equipment exceed the +demand for such equipment. The equipment can also be moved from +one market to another in response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. State and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 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. +6 +Table of Contents +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a “major source.” As a +consequence, more facilities may become major sources and thus +would be required to obtain operating permits. This permitting +process may require capital expenditures in order to comply with +permit limits. +Risks and +Insurance +Our operations are subject to the many hazards inherent in the +drilling business, including: +• +accidents at the work location, +• +blow-outs, +• +cratering, +• +fires, and +• +explosions. +7 +Table of Contents +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for public liability +and property damage to others with respect to our operations. +However, such insurance may not be sufficient to protect us +against liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. However, it does not cover the full +replacement cost of the rigs and we do not carry insurance +against loss of earnings resulting from such damage. In view of +the difficulties that may be encountered in renewing such +insurance at reasonable rates, no assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +8 +Table of Contents +Employees +We had approximately 8,100 full-time employees at +December 31, 2007. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada, and our +pressure pumping division in the Appalachian Basin to a lesser +extent, are subject to slow periods of activity during the +Spring thaw. +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. \ No newline at end of file diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/item13.txt b/raw/filings/0000889900/2007/0000950134-08-003007/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..97cbc88da95dc5aeea63960da2883c0ca43e0a25 --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/item13.txt @@ -0,0 +1,6 @@ +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/item9a.txt b/raw/filings/0000889900/2007/0000950134-08-003007/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..34160976743037c80a19f7a9c8261b898c28738d --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/item9a.txt @@ -0,0 +1,58 @@ +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2007, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO +and CFO, as appropriate to allow timely decisions regarding +required disclosure. +30 +Table of Contents +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2007, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2007. +The effectiveness of our internal control over financial +reporting as of December 31, 2007 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and is incorporated by reference into Item 8 +of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. \ No newline at end of file diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/rp_note.txt b/raw/filings/0000889900/2007/0000950134-08-003007/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2007/0000950134-08-003007/rpt_disclosure.txt b/raw/filings/0000889900/2007/0000950134-08-003007/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..62c18181dddc029d81f5591ac1cdb7e14e357689 --- /dev/null +++ b/raw/filings/0000889900/2007/0000950134-08-003007/rpt_disclosure.txt @@ -0,0 +1,27 @@ +related person transaction are considered, including whether +such transaction is in, or not inconsistent with, the best +interest of Patterson-UTI and whether, in appropriate cases, +such transaction is on commercial terms at least as favorable to +Patterson-UTI as would otherwise be available to or from an +unrelated third party or to Patterson-UTI’s employees +generally. Related person transactions generally include +transactions in an amount that exceeds $50,000 between +Patterson-UTI or any of its subsidiaries and an executive +officer, a director (or nominee to become director), an +immediate family member of any of the foregoing or any entity in +which any of the foregoing has a 10% or greater beneficial +ownership interest or in which they are an executive officer, +general partner, principal or engaged in a similar position. +Certain related person transactions have been pre-approved under +the terms of the policy, including, subject to certain +exceptions and limitations, the personal use of the +Patterson-UTI airplane by executive officers, co-investment in +oil and gas properties by Mr. Talbott and other persons +related to him, and the sale to or purchase from Patterson-UTI +of goods and services by entities related to directors in the +ordinary course of business that are immaterial to Patterson-UTI +and with respect to which the director has no direct economic +interest or decision making authority. +27 +Table of Contents +SECURITY \ No newline at end of file diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/filing.txt b/raw/filings/0000889900/2008/0000950134-09-003225/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..c50c42107c45b7983df01122d170403d8e19e73d --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/filing.txt @@ -0,0 +1,7596 @@ +10-K +1 +d66380e10vk.htm +FORM 10-K +e10vk +Table of Contents +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. +20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2008 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, +Inc. +(Exact name of registrant as +specified in its charter) +Delaware +(State or other jurisdiction +of +incorporation or organization) +75-2504748 +(I.R.S. Employer +Identification No.) +450 Gears Road, Suite 500, Houston, Texas +(Address of principal +executive offices) +77067 +(Zip +Code) +Registrant’s telephone number, including area code: +(281) 765-7100 +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 +Preferred Share Purchase Rights +Indicate by check mark if the registrant is a well-known +seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes þ or +No o +Indicate by check mark if the registrant is not required to file +reports pursuant to Section 13 or Section 15(d) of the +Act. Yes o or +No +þ +Indicate by check mark whether the registrant (1) has filed +all reports required to be filed by Section 13 or 15(d) of +the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant +was required to file such reports), and (2) has been +subject to such filing requirements for the past +90 days. Yes þ No o +Indicate by check mark if disclosure of delinquent filers +pursuant to Item 405 of +Regulation S-K +is not contained herein, and will not be contained, to the best +of the registrant’s knowledge, in definitive proxy or +information statements incorporated by reference in +Part III of this +Form 10-K +or any amendment to this +Form 10-K. þ +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, a non-accelerated +filer, or a smaller reporting company. See the definitions of +“large accelerated filer,” “accelerated +filer” and “smaller reporting company” in Rule +12b-2 of the +Exchange Act. (Check one): +Large +accelerated +filer þ +Accelerated +filer o +Non-accelerated +filer o +Smaller +reporting +company o +(Do not check if a smaller reporting company) +Indicate by check mark whether the registrant is a shell company +(as defined in Rule 12b-2 of the +Act). Yes o No +þ +The aggregate market value of the voting and non-voting common +equity held by non-affiliates of the registrant as of +June 30, 2008, the last business day of the +registrant’s most recently completed second fiscal quarter, +was $5,581,179,402, calculated by reference to the closing price +of $36.13 for the common stock on the Nasdaq National Market on +that date. +As of February 16, 2009, the registrant had outstanding +153,098,601 shares of common stock, $.01 par value, +its only class of common stock. +Documents incorporated by reference: +Definitive Proxy Statement for the 2009 Annual Meeting of +Stockholders (Part III). +Table of Contents +FORWARD-LOOKING +STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF THE +“SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES +LITIGATION REFORM ACT OF 1995 +Certain statements made in this Annual Report on +Form 10-K +and in other public filings and press releases by us contain +“forward-looking” information (as defined in the +Private Securities Litigation Reform Act of 1995) that +involves risk and uncertainty. These forward-looking statements +include, without limitation, statements relating to: liquidity; +financing of operations; continued volatility of oil and natural +gas prices; source and sufficiency of funds required for +immediate capital needs and additional rig acquisitions (if +further opportunities arise); impact of inflation; and other +matters. Our forward-looking statements can be identified by the +fact that they do not relate strictly to historic or current +facts and often use words such as “believes,” +“budgeted,” “expects,” +“estimates,” “project,” “will,” +“could,” “may,” “plans,” +“intends,” “strategy,” or +“anticipates,” and other words and expressions of +similar meaning. The forward-looking statements are based on +certain assumptions and analyses we make in light of our +experience and our perception of historical trends, current +conditions, expected future developments and other factors we +believe are appropriate in the circumstances. Although we +believe that the expectations reflected in such forward-looking +statements are reasonable, we can give no assurance that such +expectations will prove to have been correct. Forward-looking +statements may be made by management orally or in writing, +including, but not limited to, Management’s Discussion and +Analysis of Financial Condition and Results of Operations +included in this Annual Report on +Form 10-K +and other sections of our filings with the United States +Securities and Exchange Commission (the “SEC”) under +the Securities Exchange Act of 1934 and the Securities Act of +1933. +Forward-looking statements are not guarantees of future +performance and a variety of factors could cause actual results +to differ materially from the anticipated or expected results +expressed in or suggested by these forward-looking statements. +Factors that might cause or contribute to such differences +include, but are not limited to, deterioration of global +economic conditions, declines in oil and natural gas prices that +could adversely affect demand for our services and their +associated effect on day rates, rig utilization and planned +capital expenditures, excess availability of land drilling rigs, +including as a result of the reactivation or construction of new +land drilling rigs, adverse industry conditions, adverse credit +and equity market conditions, difficulty in integrating +acquisitions, demand for oil and natural gas, shortages of rig +equipment and ability to retain management and field personnel. +Refer to “Risk Factors” contained in Part 1 of +this Annual Report on +Form 10-K +for a more complete discussion of these and other factors that +might affect our performance and financial results. These +forward-looking statements are intended to relay our +expectations about the future, and speak only as of the date +they are made. We undertake no obligation to publicly update or +revise any forward-looking statement, whether as a result of new +information, future events or otherwise. +PART I +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the +SEC. The information contained on our website is not part of +this Report or other filings that we make with the SEC. You may +read and copy any materials we file with the SEC at the +SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the +operation of the Public Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site (www.sec.gov) that contains +reports, proxy and information statements and other information +regarding issuers that file electronically with the SEC. +Overview +Based on publicly available information, we believe we are the +second largest operator of land-based drilling rigs in the +United States. The Company was formed in 1978 and reincorporated +in 1993 as a Delaware corporation. +1 +Table of Contents +Our contract drilling business operates primarily in Texas, New +Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, +Colorado, Arizona, Utah, Wyoming, Montana, North Dakota, South +Dakota, Pennsylvania, West Virginia and western Canada. +As of December 31, 2008, we had a drilling fleet that +consisted of 344 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drilling rig components and equipment. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, New Mexico, Oklahoma and Louisiana. +Drilling and completion fluids are used by oil and natural gas +operators to control pressure when drilling and completing oil +and natural gas wells. We own and invest in oil and natural gas +assets as a working interest owner. Our oil and natural gas +interests are located primarily in Texas, New Mexico, +Mississippi and Louisiana. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2008, 2007 +and 2006, except that in 2008 our drilling and completion fluids +services segment reported an operating loss due to a non-cash +charge recognized for the impairment of goodwill in that segment. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 14 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2008, we had 344 marketable land-based +drilling rigs which were based in the following regions: +• +93 in west Texas and southeastern New Mexico, +• +92 in north central and eastern Texas, northern Louisiana, +Mississippi and Alabama, +• +56 in the Rocky Mountain region (Colorado, Arizona, Utah, +Wyoming, Montana, North Dakota and South Dakota), +• +50 in south Texas and southern Louisiana, +• +27 in the Texas panhandle, Oklahoma and Arkansas, +• +6 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Eighty seven of these drilling rigs are electric rigs and 257 +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 +2 +Table of Contents +electricity to power the rig. We also have a substantial +inventory of drilling rig components and equipment which may be +used in the activation of additional drilling rigs or as +replacement parts for marketable rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.4 billion during the last three years on capital +expenditures to (1) build new land drilling rigs and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2008, 2007 and 2006, we spent approximately +$361 million, $540 million and $531 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. Our rigs are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well basis or a term basis. Well-to-well contracts are +generally short-term in nature and cover the drilling of a +single well or a series of wells. Term contracts are entered +into for a specified period of time (frequently one to three +years) and provide for the use of the drilling rig to drill +multiple wells. During 2008, our average number of days to drill +a well (which includes moving to the drill site, rigging up and +rigging down) was approximately 22 days. +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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. We generally +indemnify our customers against claims by our employees and +claims that might arise from surface pollution caused by spills +of fuel, lubricants and other solvents within our control. The +customers generally indemnify us against claims that might arise +from other surface and subsurface pollution, except claims that +might arise from our gross negligence. Each drilling contract +will contain the actual terms setting forth our rights and +obligations and those of the particular customer. +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. All of our contracts during the years +ended December 31, 2008, 2007 and 2006 provided for payment +on a daywork basis. Our bid for each contract depends upon +location, depth and anticipated complexity of the well, +on-site +drilling conditions, equipment to be used, estimated risks +involved, estimated duration of the job, availability of +drilling rigs and other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving, or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. All of our drilling contracts in 2006, 2007 and +2008 were daywork contracts. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling +3 +Table of Contents +contractor than daywork contracts. Under footage contracts, the +drilling contractor typically assumes certain risks associated +with loss of the well from fire, blowouts and other risks. We +did not enter into any footage contracts in the past three years. +Turnkey +Contracts +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed scope of +the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. We did not enter into any turnkey contracts +in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2008 +2007 +2006 +Average rigs operating(1) +254 +244 +296 +Number of rigs operated +315 +338 +331 +Number of wells drilled +4,218 +4,237 +5,050 +Number of operating days +93,068 +89,095 +108,221 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2008 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +65 +9 +74 +12,000 to 15,999 +197 +8 +205 +16,000 to 30,000 +62 +— +62 +Totals +324 +20 +344 +At December 31, 2008, we owned and operated 308 trucks and +405 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations, particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion +4 +Table of Contents +of new wells and remedial work on existing wells. Most wells +drilled in the Appalachian Basin require some form of fracturing +or other stimulation to enhance the flow of oil and natural gas +by pumping fluids under pressure into the well bore. Generally, +Appalachian Basin wells require cementing services before +production commences. The cementing process inserts material +between the wall of the well bore and the casing to center and +stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2008 includes: +• +42 cement pumper trucks, +• +66 triplex pumper trucks, +• +54 nitrogen pumper trucks, +• +5 quintiplex pump trailers, +• +31 blender trucks, +• +28 bulk acid trucks/acid pumper trucks, +• +47 bulk cement trucks, +• +27 bulk nitrogen trucks, +• +6 bulk nitrogen tractor trailer combinations, +• +69 bulk sand trucks, +• +14 sand pneumatic trucks, +• +7 sand pneumatic trailers, +• +9 flatbed material trucks, +• +24 connection trucks, +• +2 shale fracturing manifold trailers, +• +1 shale fracturing iron trailer, +• +8 shale fracturing sand field bins with conveyors, +• +2 shale fracturing large conveyors, and +• +21 tractors. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We serve our offshore +customers through six stockpoint facilities located along the +Gulf of Mexico in Texas and Louisiana and our land-based +customers through fourteen stockpoint facilities in Texas, +Louisiana, Oklahoma and New Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to promote effective application of the products +and systems used to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +5 +Table of Contents +Raw Materials — The profitability of our +drilling and completion fluids operations is affected by the +availability and pricing 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 we have with producers of these raw +materials. +Barite Grinding Facility — We operate a barite +grinding facility with two barite grinding mills in Houma, +Louisiana. This facility allows us to grind raw barite into the +powder additive used in drilling fluids. +Other Equipment — We own and operate 13 trucks +and 141 trailers and lease another 34 trucks which are used to +transport drilling and completion fluids and related equipment. +Oil and +Natural Gas Operations +General — We have been engaged in the +development, exploration, acquisition and production of oil and +natural gas. Through October 31, 2007, we served as +operator with respect to several properties and were actively +involved in the development, exploration, acquisition and +production of oil and natural gas. Effective November 1, +2007, we sold the related operations portion of our exploration +and production business, which was the portion of that business +that actively managed the development, exploration, acquisition +and production of oil and natural gas. We continue to own and +invest in oil and natural gas assets as a working interest +owner. Our oil and natural gas interests are located primarily +in producing regions of Texas, New Mexico, Mississippi and +Louisiana. +Customers +The customers of each of our three oil service business segments +are oil and natural gas operators. Our customer base includes +both major and independent oil and natural gas operators. During +2008, no single customer accounted for 10% or more of our +consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping +Businesses — Our land drilling and pressure +pumping businesses are highly competitive. At times, available +land drilling rigs and pressure pumping equipment exceed the +demand for such equipment. The equipment can also be moved from +one market to another in response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, +6 +Table of Contents +compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. State and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 operated by us or our +predecessors. In addition, some of these properties have been +operated by third parties over whom we have no control of their +treatment of hydrocarbon and other materials or the manner in +which they may have disposed of or released such materials. +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a +7 +Table of Contents +“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, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for bodily injury and +property damage to others with respect to our operations. Such +insurance, however, may not be sufficient to protect us against +liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. Such insurance does not, however, cover the +full replacement cost of the rigs, and we do not carry insurance +against loss of earnings resulting +8 +Table of Contents +from such damage. In view of the difficulties that may be +encountered in renewing such insurance at reasonable rates, no +assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +Employees +We had approximately 6,600 full-time employees at +December 31, 2008. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada, and our +pressure pumping division in the Appalachian Basin to a lesser +extent, are subject to slow periods of activity during the +Spring thaw. +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. +Item 1A. +Risk +Factors. +You should consider each of the following factors as well as the +other information in this Report in evaluating our business and +our prospects. Additional risks and uncertainties not presently +known to us or that we currently consider immaterial may also +impair our business operations. If any of the following risks +actually occur, our business and financial results could be +harmed. You should also refer to the other information set forth +in this Report, including our financial statements and the +related notes. +Global +Economic Conditions May Adversely Affect Our Operating +Results. +During recent months, there has been a significant decline in +oil and natural gas prices. During this time there has also been +a significant deterioration in the global economic environment. +As part of this deterioration, there has been significant +uncertainty in the capital markets and access to financing has +been reduced. As a result of these conditions, customers have +recently started reducing or curtailing their drilling programs, +which is resulting in a significant decrease in demand for our +services. Furthermore, these factors could result in certain of +our customers experiencing an inability to pay suppliers, +including us, if they are not able to access capital to fund +their operations. These conditions could have a material adverse +effect on our business, financial condition, cash flows and +results of operations. +We are +Dependent on the Oil and Natural Gas Industry and Market Prices +for Oil and Natural Gas. Declines in Oil and Natural Gas Prices +Have Adversely Affected Our Operating Results. +Our revenue, profitability and rate of growth are substantially +dependent upon prevailing prices for natural gas and, to a +lesser extent, oil. For many years, oil and natural gas prices +and markets have been extremely volatile. Prices are affected by: +• +market supply and demand, +• +international military, political and economic +conditions, and +• +the ability of the Organization of Petroleum Exporting +Countries, commonly known as OPEC, to set and maintain +production and price targets. +9 +Table of Contents +All of these factors are beyond our control. During 2008, the +monthly average market price of natural gas peaked in June at +$13.06 per Mcf before rapidly declining to an average of $5.99 +per Mcf in December. In January 2009, the average market +price of natural gas declined further to $5.40 per Mcf. This +decline in the market price of natural gas has resulted in our +customers significantly reducing their drilling activities +beginning in the fourth quarter of 2008 and continuing into +2009. This reduction in demand combined with the reactivation +and construction of new land drilling rigs in the United States +during the last several years has resulted in excess capacity +compared to demand. As a result of these factors, our average +number of rigs operating has recently declined significantly. We +expect oil and natural gas prices to continue to be volatile and +to affect our financial condition, operations and ability to +access sources of capital. Continued low market prices for +natural gas will likely result in further decreases in demand +for our drilling rigs and adversely affect our operating results. +A +General Excess of Operable Land Drilling Rigs Adversely Affects +Our Profit Margins Particularly in Times of Weaker +Demand. +The North American land drilling industry has experienced +periods of downturn in demand over the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins during +the downturn periods. +In addition to adverse effects that declines in demand could +have on us, ongoing factors which could continue to adversely +affect utilization rates and pricing, even in an environment of +high oil and natural gas prices and increased drilling activity, +include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new drilling rigs. +As a result of an increase in drilling activity and increased +prices for drilling services in recent years, construction of +new drilling rigs increased significantly. The addition of new +drilling rigs to the market and the recent decrease in demand +has resulted in excess capacity. We cannot predict either the +future level of demand for our contract drilling services or +future conditions in the oil and natural gas contract drilling +business. +Shortages +of Drill Pipe, Replacement Parts and Other Related Rig Equipment +Adversely Affects Our Operating Results. +During periods of increased demand for drilling services, the +industry has experienced shortages of drill pipe, replacement +parts and other related rig equipment. These shortages can cause +the price of these items to increase significantly and require +that orders for the items be placed well in advance of expected +use. These price increases and delays in delivery may require us +to increase capital and repair expenditures in our contract +drilling segment. Severe shortages could impair our ability to +operate our drilling rigs. +The +Oil Service Business Segments in Which We Operate Are Highly +Competitive with Excess Capacity, which Adversely Affect Our +Operating Results. +Our land drilling and pressure pumping businesses are highly +competitive. At times, available land drilling rigs and pressure +pumping equipment exceed the demand for such equipment. This +excess capacity has resulted in substantial competition for +drilling and pressure pumping contracts. The fact that drilling +rigs and pressure pumping equipment are mobile and can be moved +from one market to another in response to market conditions +heightens the competition in the industry. +We believe that price competition for drilling and pressure +pumping contracts will continue for the foreseeable future due +to the existence of available rigs and pressure pumping +equipment. +In recent years, many drilling and pressure pumping companies +have consolidated or merged with other companies. Although this +consolidation has decreased the total number of competitors, we +believe the competition for drilling and pressure pumping +services will continue to be intense. +The drilling and completion fluids services industry is highly +competitive. Price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the +10 +Table of Contents +reputation of the fluids services provider in the drilling +industry and relationships with customers. Some of our +competitors have substantially more resources and longer +operating histories than we have. +Labor +Shortages Adversely Affect Our Operating Results. +During periods of increasing demand for contract drilling and +pressure pumping services, the industry experiences shortages of +qualified personnel. During these periods, our ability to +attract and retain sufficient qualified personnel to market and +operate our drilling rigs and pressure pumping equipment is +adversely affected, which negatively impacts both our operations +and profitability. Operationally, it is more difficult to hire +qualified personnel, which adversely affects our ability to +mobilize inactive rigs and pressure pumping equipment in +response to the increased demand for such services. +Additionally, wage rates for drilling and pressure pumping +personnel are likely to increase during periods of increasing +demand, resulting in higher operating costs. +Continued +Growth Through Rig Acquisition is Not Assured. +We have increased our drilling rig fleet in the past through +mergers, acquisitions and rig construction. The land drilling +industry has experienced significant consolidation, and there +can be no assurance that acquisition opportunities will be +available in the future. Additionally, we are likely to continue +to face intense competition from other companies for available +acquisition opportunities. +There can be no assurance that we will: +• +have sufficient capital resources to complete additional +acquisitions, +• +successfully integrate acquired operations and assets, +• +effectively manage the growth and increased size, +• +successfully deploy idle or stacked rigs, +• +maintain the crews and market share to operate drilling rigs +acquired, or +• +successfully improve our financial condition, results of +operations, business or prospects as a result of any completed +acquisition. +We may incur substantial indebtedness to finance future +acquisitions and also may issue equity securities or convertible +securities in connection with any such acquisitions. Debt +service requirements could represent a significant burden on our +results of operations and financial condition and the issuance +of additional equity would be dilutive to existing stockholders. +Also, continued growth could strain our management, operations, +employees and other resources. +The +Nature of our Business Operations Presents Inherent Risks of +Loss that, if not Insured or Indemnified Against, Could +Adversely Affect Our Operating Results. +Our operations are subject to many hazards inherent in the +contract drilling, pressure pumping, and drilling and completion +fluids businesses, which in turn could cause personal injury or +death, work stoppage, or serious damage to our equipment. Our +operations could also cause environmental and reservoir damages. +We maintain insurance coverage and have indemnification +agreements with many of our customers. However, there is no +assurance that such insurance or indemnification agreements +would adequately protect us against liability or losses from all +consequences of these hazards. Additionally, there can be no +assurance that insurance would be available to cover any or all +of these risks, or, even if available, that insurance premiums +or other costs would not rise significantly in the future, so as +to make the cost of 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, general liability +and equipment insurance coverages. +Violations +of Environmental Laws and Regulations Could Materially Adversely +Affect Our Operating Results. +The drilling of oil and natural gas wells is subject to various +Federal, state, foreign, and local laws, rules and regulations. +The cost of compliance with these laws and regulations could be +substantial. A failure to comply with these requirements could +expose us to substantial civil and criminal penalties. In +addition, Federal law imposes a +11 +Table of Contents +variety of regulations on “responsible parties” +related to the prevention of oil spills and liability for +damages from such spills. As an owner and operator of land-based +drilling rigs, we may be deemed to be a responsible party under +Federal law. Our operations and facilities are subject to +numerous state and Federal environmental laws, rules and +regulations, including, without limitation, laws concerning the +containment and disposal of hazardous substances, oil field +waste and other waste materials, the use of underground storage +tanks and the use of underground injection wells. +Anti-takeover +Measures in Our Charter Documents and Under State Law Could +Discourage an Acquisition and Thereby Affect the Related +Purchase Price. +We are a Delaware corporation subject to the Delaware General +Corporation Law, including Section 203, an anti-takeover +law enacted in 1988. We have also enacted certain anti-takeover +measures, including a stockholders’ rights plan. In +addition, our Board of Directors has the authority to issue up +to one million shares of preferred stock and to determine the +price, rights (including voting rights), conversion ratios, +preferences and privileges of that stock without further vote or +action by the holders of the common stock. As a result of these +measures and others, potential acquirers might find it more +difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our +securities of certain opportunities to sell or otherwise dispose +of the securities at above-market prices pursuant to any such +transactions. +Item 1B. +Unresolved +Staff Comments. +None. +Item 2. +Properties +Our corporate headquarters are located in Houston, Texas and +include approximately 12,000 square feet of leased office +space. These headquarters are located at 450 Gears Road, +Suite 500, Houston, Texas, and our telephone number at that +address is +(281) 765-7100. +Our primary administrative office is located in Snyder, Texas +and includes approximately 37,000 square feet of office and +storage space. We also have administrative offices, yards and +stockpoint facilities in many of the areas in which we operate. +The facilities are primarily used to support day-to-day +operations, including the repair and maintenance of equipment as +well as the storage of equipment, inventory and supplies and to +facilitate administrative responsibilities and sales. +Contract Drilling Operations — Our drilling +services are supported by several administrative offices and +yard facilities located throughout our areas of operations +including Texas, New Mexico, Oklahoma, Colorado, Utah, Wyoming +and western Canada. +Pressure Pumping — Our pressure pumping +services are supported by several offices and yard facilities +located throughout our areas of operations including +Pennsylvania, Ohio, New York, West Virginia, Kentucky, +Tennessee, Wyoming and Colorado. +Drilling and Completion Fluids — Our drilling +and completion fluids services are supported by several +administrative offices and stockpoint facilities located +throughout our areas of operations including Texas, Louisiana, +New Mexico and Oklahoma. +Oil and Natural Gas Working Interests — Our +interests in oil and natural gas properties are located in +Texas, New Mexico, Mississippi and Louisiana. +We own our administrative offices in Snyder, Texas, as well as +several of our other facilities. We also lease a number of +facilities, and we do not believe that any one of the leased +facilities is individually material to our operations. We +believe that our existing facilities are suitable and adequate +to meet our needs. +Item 3. +Legal +Proceedings. +We are party to various legal proceedings arising in the normal +course of our business. We do not believe that the outcome of +these proceedings, either individually or in the aggregate, will +have a material adverse effect on our results of operations, +cash flows or financial condition. +Item 4. +Submission +of Matters to a Vote of Security Holders. +None. +12 +Table of Contents +PART II +Item 5. +Market +for Registrant’s Common Equity, Related Stockholder Matters +and Issuer Purchases of Equity Securities. +(a) +Market +Information +Our common stock, par value $0.01 per share, is publicly traded +on the Nasdaq National Market and is quoted under the symbol +“PTEN.” Our common stock is included in the S&P +MidCap 400 Index and several other market indices. The following +table provides high and low sales prices of our common stock for +the periods indicated: +High +Low +2007: +First quarter +$ +24.89 +$ +21.13 +Second quarter +27.66 +22.17 +Third quarter +26.48 +20.79 +Fourth quarter +23.22 +18.44 +2008: +First quarter +$ +26.38 +$ +17.40 +Second quarter +36.40 +25.71 +Third quarter +37.45 +17.85 +Fourth quarter +19.64 +8.64 +(b) +Holders +As of February 16, 2009, there were approximately 2,300 +holders of record of our common stock. +(c) +Dividends +and Buyback Program +We paid cash dividends during the years ended December 31, +2007 and 2008 as follows: +Per Share +Total +(In thousands) +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends +$ +0.44 +$ +68,561 +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +13 +Table of Contents +On February 11, 2009, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.05 per +share to be paid on March 31, 2009 to holders of record as +of March 12, 2009. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +The table below sets forth the information with respect to +purchases of our common stock made by us during the quarter +ended December 31, 2008. +Approximate +Total number +dollar value +of shares +of shares +(or units) +that may yet +purchased as +be purchased +part of +under the +Total number +Average price +publicly announced +plans or +of shares +paid per +plans or +programs +Period covered +purchased +share +programs(1) +(In thousands)(1) +October 1–31, 2008 +— +$ +— +— +$ +129,285 +November 1–30, 2008 +671,000 +$ +11.13 +671,000 +$ +121,815 +December 1–31, 2008 +829,000 +$ +10.24 +829,000 +$ +113,326 +Total +1,500,000 +$ +10.64 +1,500,000 +$ +113,326 +(1) +On August 2, 2007, we announced that our Board of Directors +approved a stock buyback program authorizing purchases of up to +$250 million of our common stock in open market or +privately negotiated transactions. +(d) +Securities +Authorized for Issuance Under Equity Compensation +Plans +Equity compensation plan information as of December 31, +2008 follows: +Equity Compensation Plan Information +Number of +Number of +Securities +Securities to +Remaining Available +be Issued upon +for Future Issuance +Exercise of +Weighted-Average +under Equity +Outstanding +Exercise Price +Compensation Plans +Options, +of Outstanding +(Excluding Securities +Warrants and +Options, Warrants +Reflected in +Plan Category +Rights +and Rights +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved by security holders(1) +5,684,634 +$ +21.70 +4,637,004 +Equity compensation plans not approved by security holders(2) +248,938 +$ +9.94 +— +Total +5,933,572 +$ +21.20 +4,637,004 +(1) +The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended (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, officers +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. +(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 officers 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. +14 +Table of Contents +(e) +Performance +Graph +The following graph compares the cumulative stockholder return +of our common stock for the period from December 31, 2003 +through December 31, 2008, with the cumulative total return +of the Standard & Poors 500 Stock Index, the +Standard & Poors MidCap Index, the Oilfield Service +Index and a peer group determined by us. Our 2007 peer group +consists of Grey Wolf, Inc., Helmerich & Payne, Inc., +Nabors Industries, Ltd., Pioneer Drilling Co. and Unit Corp. We +evaluated our peer group for 2008 and determined it was +appropriate to add certain members. Our 2008 peer group consists +of BJ Services Company, Bronco Drilling Company, Inc., +Helmerich & Payne, Inc., Nabors Industries, Ltd., +Pioneer Drilling Co., Precision Drilling Trust, Superior Well +Services, Inc. and Unit Corp. Grey Wolf Inc. was acquired by +Precision Drilling Trust in December 2008 and we have removed +them from our 2008 peer group. All of the companies in our peer +group are providers of land-based drilling and pressure pumping +services. The graph assumes investment of $100 on +December 31, 2003 and reinvestment of all dividends. +Fiscal Year Ended December 31, +2003 +2004 +2005 +2006 +2007 +2008 +Company/Index +($) +($) +($) +($) +($) +($) +Patterson-UTI Energy, Inc. +100.00 +118.70 +202.23 +144.15 +123.54 +75.18 +2007 Peer Group Index +100.00 +129.84 +198.24 +160.02 +166.05 +69.51 +2008 Peer Group Index +100.00 +129.64 +201.19 +161.53 +151.57 +76.18 +S&P 500 Stock Index +100.00 +110.88 +116.33 +134.70 +142.10 +89.53 +Oilfield Service Index (OSX) +100.00 +135.32 +202.85 +231.52 +339.83 +138.31 +S&P MidCap Index +100.00 +116.48 +131.11 +144.64 +156.18 +99.59 +The foregoing graph is based on historical data and is not +necessarily indicative of future performance. This graph shall +not be deemed to be “soliciting material” or to be +“filed” with the SEC or subject to Regulations 14A or +14C under the Exchange Act or to the liabilities of +Section 18 under such Act. +15 +Table of Contents +Item 6. +Selected +Financial Data. +Our selected consolidated financial data as of December 31, +2008, 2007, 2006, 2005 and 2004, and for each of the five years +in the period ended December 31, 2008 should be read in +conjunction with “Management’s Discussion and Analysis +of Financial Condition and Results of Operations” and the +Consolidated Financial Statements and related Notes thereto, +included as Items 7 and 8, respectively, of this Report. +Certain reclassifications have been made to the historical +financial data to conform with the 2008 presentation. +Years Ended December 31, +2008 +2007 +2006 +2005 +2004 +(In thousands, except per share amounts) +Income Statement Data: +Operating revenues: +Contract drilling +$ +1,804,026 +$ +1,741,647 +$ +2,169,370 +$ +1,485,684 +$ +809,691 +Pressure pumping +217,494 +202,812 +145,671 +93,144 +66,654 +Drilling and completion fluids +145,246 +128,098 +192,358 +122,011 +90,557 +Oil and natural gas +42,360 +41,637 +39,187 +39,616 +33,867 +Total +2,209,126 +2,114,194 +2,546,586 +1,740,455 +1,000,769 +Operating costs and expenses: +Contract drilling +1,038,327 +963,150 +1,002,001 +776,313 +556,869 +Pressure pumping +132,570 +105,273 +77,755 +54,956 +37,561 +Drilling and completion fluids +126,900 +108,752 +150,372 +98,530 +76,503 +Oil and natural gas +12,793 +10,864 +13,374 +9,566 +7,978 +Goodwill impairment +9,964 +— +— +— +— +Depreciation, depletion and other impairment +268,431 +249,206 +196,370 +156,393 +122,800 +Selling, general and administrative +68,190 +64,623 +55,065 +39,110 +31,983 +Embezzlement costs (recoveries) +— +(43,955 +) +3,081 +20,043 +19,122 +Net loss (gain) on asset disposals/retirements +6,071 +(16,545 +) +3,819 +(1,231 +) +(1,411 +) +Other operating expenses +4,350 +2,550 +5,585 +5,479 +897 +Total +1,667,596 +1,443,918 +1,507,422 +1,159,159 +852,302 +Operating income +541,530 +670,276 +1,039,164 +581,296 +148,467 +Other income +1,418 +531 +4,670 +3,463 +680 +Income before income taxes and cumulative effect of change in +accounting principle +542,948 +670,807 +1,043,834 +584,759 +149,147 +Income tax expense +195,879 +232,168 +371,267 +212,019 +54,801 +Income before cumulative effect of change in accounting principle +347,069 +438,639 +672,567 +372,740 +94,346 +Cumulative effect of change in accounting principle, net of +related income tax expense of $398 +— +— +687 +— +— +Net income +$ +347,069 +$ +438,639 +$ +673,254 +$ +372,740 +$ +94,346 +Income before cumulative effect of change in accounting +principle per common share: +Basic +$ +2.26 +$ +2.83 +$ +4.07 +$ +2.19 +$ +0.57 +Diluted +$ +2.24 +$ +2.79 +$ +4.02 +$ +2.15 +$ +0.56 +16 +Table of Contents +Years Ended December 31, +2008 +2007 +2006 +2005 +2004 +(In thousands, except per share amounts) +Net income per common share: +Basic +$ +2.26 +$ +2.83 +$ +4.08 +$ +2.19 +$ +0.57 +Diluted +$ +2.24 +$ +2.79 +$ +4.02 +$ +2.15 +$ +0.56 +Cash dividends per common share +$ +0.60 +$ +0.44 +$ +0.28 +$ +0.16 +$ +0.06 +Weighted average number of common shares outstanding: +Basic +153,379 +154,755 +165,159 +170,426 +166,258 +Diluted +154,717 +156,997 +167,413 +173,767 +169,211 +Balance Sheet Data: +Total assets +$ +2,712,817 +$ +2,465,199 +$ +2,192,503 +$ +1,795,781 +$ +1,256,785 +Borrowings under line of credit +— +50,000 +120,000 +— +— +Stockholders’ equity +2,126,942 +1,896,030 +1,562,466 +1,367,011 +961,501 +Working capital +338,761 +227,577 +335,052 +382,448 +235,480 +17 +Table of Contents +Item 7. +Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +This Report, including this Item 7, contains +forward-looking statements, which are made pursuant to the +“Safe Harbor” provisions of the Private Securities +Litigation Reform Act of 1995. +Management Overview — We are a leading provider +of contract services to the North American oil and natural gas +industry. Our services primarily involve the drilling, on a +contract basis, of land-based oil and natural gas wells and, to +a lesser extent, we provide pressure pumping services and +drilling and completion fluid services. In addition to the +aforementioned contract services, we also invest, on a working +interest basis, in oil and natural gas properties. For the three +years ended December 31, 2008, our operating revenues +consisted of the following (dollars in thousands): +2008 +2007 +2006 +Contract drilling +$ +1,804,026 +82 +% +$ +1,741,647 +82 +% +$ +2,169,370 +84 +% +Pressure pumping +217,494 +10 +202,812 +10 +145,671 +6 +Drilling and completion fluids +145,246 +6 +128,098 +6 +192,358 +8 +Oil and natural gas +42,360 +2 +41,637 +2 +39,187 +2 +$ +2,209,126 +100 +% +$ +2,114,194 +100 +% +$ +2,546,586 +100 +% +We provide our contract services to oil and natural gas +operators in many of the oil and natural gas producing regions +of North America. Our contract drilling operations are focused +in various regions of Texas, New Mexico, Oklahoma, Arkansas, +Louisiana, Mississippi, Alabama, Colorado, Arizona, Utah, +Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West +Virginia and western Canada, while our pressure pumping services +are focused primarily in the Appalachian Basin. Our drilling and +completion fluids services are provided to operators offshore in +the Gulf of Mexico and on land in Texas, Southeastern New +Mexico, Oklahoma and the Gulf Coast region of Louisiana. The oil +and natural gas properties in which we hold interests are +primarily located in Texas, New Mexico, Mississippi and +Louisiana. +Typically, the profitability of our business is most readily +assessed by two primary indicators in our contract drilling +segment: our average number of rigs operating and our average +revenue per operating day. During 2008, our average number of +rigs operating was 254 compared to 244 in 2007 and 296 in 2006. +Our average revenue per operating day was $19,380 in 2008 +compared to $19,550 in 2007 and $20,050 in 2006. Our +consolidated net income for 2008 decreased by +$91.6 million, or 21%, as compared to 2007. Included in +consolidated net income for 2007 was a pre-tax gain of +approximately $44.0 million associated with the recovery of +embezzled funds. Excluding this recovery in 2007, our +consolidated net income for 2007 would have been approximately +$410 million and the decrease in net income for 2008 would +have been approximately $62.8 million or 15%. The decrease +in consolidated net income in 2008 was primarily due to our +contract drilling segment experiencing a decrease in operating +income of $27.8 million driven by a decrease in average +revenue per operating day and an increase in average costs per +operating day; our pressure pumping segment experiencing a +decrease in operating income of $22.2 million driven by an +increase in average direct operating costs per job; the +recognition of an impairment of goodwill in the amount of +$9.964 million in our drilling and completion fluids +segment; and losses incurred on the disposal and retirement of +assets in 2008 of $6.1 million as compared to a gain on +disposal of assets in 2007 of $16.5 million. +Our revenues, profitability and cash flows are highly dependent +upon prevailing prices for natural gas and, to a lesser extent, +oil. During periods of improved commodity prices, the capital +spending budgets of oil and natural gas operators tend to +expand, which generally results in increased demand for our +contract services. Conversely, in periods when these commodity +prices deteriorate, the demand for our contract services +generally weakens and we experience downward pressure on pricing +for our services. During recent months, there has been a +significant decline in oil and natural gas prices. During this +time there has also been a substantial deterioration in the +global economic environment. As part of this deterioration, +there has been substantial uncertainty in the capital markets +and access to financing has been reduced. Due to these +conditions, customers have recently started reducing or +curtailing their drilling programs, which is resulting in a +decrease in demand for our services, as evidenced by the decline +in our monthly average rigs operating from 283 in October 2008 +to 162 in January 2009. Furthermore, these factors could result +in certain of our customers experiencing an inability to pay +suppliers, including us, if they are +18 +Table of Contents +not able to access capital to fund their operations. We are also +highly impacted by competition, the availability of excess +equipment, labor issues and various other factors that could +materially adversely affect our business, financial condition, +cash flows and results of operations which are more fully +described as “Risk Factors” in Item 1A of this +Report. +We believe that the liquidity shown on our balance sheet as of +December 31, 2008, which includes approximately +$339 million in working capital (including +$81.2 million in cash) and approximately +$316.5 million currently available under our current +$375 million revolving line of credit, together with cash +expected to be generated from operations, provides us with +sufficient ability to fund our 2009 plans to build new +equipment, make improvements to our existing equipment, expand +into new regions, pay cash dividends and survive the current +downturn in our industry. +Commitments and Contingencies — We maintain +letters of credit in the aggregate amount of $58.5 million +for the benefit of various insurance companies as collateral for +retrospective premiums and retained losses which could become +payable under the terms of the underlying insurance contracts. +These letters of credit expire at various times during each +calendar year and are typically renewed annually. As of +December 31, 2008, no amounts had been drawn under the +letters of credit. +As of December 31, 2008, we had commitments to purchase +approximately $269 million of major equipment. +Trading and investing — We have not engaged in +trading activities that include high-risk securities, such as +derivatives and non-exchange traded contracts. We invest cash +primarily in highly liquid, short-term investments such as +overnight deposits and money market accounts. +Description of business — We conduct our +contract drilling operations in Texas, New Mexico, Oklahoma, +Arkansas, Louisiana, Mississippi, Alabama, Colorado, Arizona, +Utah, Wyoming, Montana, North Dakota, South Dakota, +Pennsylvania, West Virginia and western Canada. For the years +ended December 31, 2008, 2007 and 2006, revenue earned +outside of the United States was $88.5 million, +$72.9 million and $98.5 million, respectively. +Additionally, we had long-lived assets located outside of the +United States of $67.2 million and $91.6 million as of +December 31, 2008 and 2007, respectively. As of +December 31, 2008, we had 344 marketable land-based +drilling rigs. We provide pressure pumping services to oil and +natural gas operators primarily in the Appalachian Basin. These +services consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, New Mexico, Oklahoma and Louisiana. +Drilling and completion fluids are used by oil and natural gas +operators during the drilling process to control pressure when +drilling oil and natural gas wells. We also invest, on a working +interest basis, in oil and natural gas properties. +Critical +Accounting Policies +In addition to established accounting policies, our consolidated +financial statements are impacted by certain estimates and +assumptions made by management. The following is a discussion of +our critical accounting policies pertaining to property and +equipment, oil and natural gas properties, goodwill, revenue +recognition and the use of estimates. +Property and equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our +long-lived assets, including property and equipment, for +impairment when events or changes in circumstances indicate that +the carrying values of certain assets may not be recovered over +their estimated remaining useful lives. In connection with this +review, assets are grouped at the lowest level at which +identifiable cash flows are largely independent of other asset +groupings. The cyclical nature of our industry has resulted in +fluctuations in rig utilization over periods of time. Management +believes that the contract drilling industry will continue to be +cyclical and rig utilization will fluctuate. Based on +management’s expectations of future trends, we estimate +future cash flows over the life of the respective assets in our +assessment of impairment. These +19 +Table of Contents +estimates of cash flows are based on historical cyclical trends +in the industry as well as management’s expectations +regarding the continuation of these trends in the future. +Provisions for asset impairment are charged against income when +estimated future cash flows, on an undiscounted basis, are less +than the asset’s net book value. Any provision for +impairment is measured based on discounted cash flows. +During 2008, we evaluated our fleet of marketable drilling rigs +and identified 22 rigs that we determined would no longer be +marketed as rigs. The components which made up these rigs were +evaluated, and those components with continuing utility to our +other marketed rigs (with a net book value of +$13.4 million) were transferred to our yards to be used as +spare equipment. The remaining components of these rigs were +retired and the associated net book value of $10.4 million +was expensed in our statement of operations as a component of +“net loss (gain) on asset disposals/retirements”. +In the fourth quarter of 2008, we experienced a significant +decrease in the number of our rigs operating and oil and natural +gas prices decreased significantly. These events were deemed by +us to be triggering events that required us to perform an +assessment with respect to impairment of long-lived assets, +including property and equipment, in our contract drilling, +drilling and completion fluids and oil and natural gas segments. +With respect to the long-lived assets in our contract drilling +and drilling and completion fluids segments, we estimated future +cash flows over the expected life of the long-lived assets, +which were comprised primarily of property and equipment, and +determined that, on an undiscounted basis, expected cash flows +exceeded the carrying value of the long-lived assets. Based on +this assessment, no impairment was indicated. Impairment +considerations in our oil and natural gas segment related to +proved properties are discussed below. No triggering event has +occurred with respect to our pressure pumping segment as the +level of activity and revenue growth in that segment has not +been impacted to the same degree as in our other segments. There +were no material impairment charges related to property and +equipment during the years 2008, 2007 or 2006. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. In accordance with 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 whether sufficient progress is being made in +assessing the reserves and the economic operating viability of +the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project 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 field. +We review our proved oil and natural gas properties for +impairment when a triggering event occurs such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on our +expectation of future pricing over the lives of the respective +fields. These estimates are then reviewed by an independent +petroleum engineer. If the net book value of a field exceeds its +undiscounted cash flow estimate, impairment expense is measured +and recognized as the difference between its net book value and +discounted cash flow. Unproved oil and natural gas properties +are reviewed quarterly to assess potential impairment. The +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, $3.9 million +and $5.0 million for the years ended December 31, +2008, 2007 and 2006, respectively, is included in depreciation, +depletion and impairment in the accompanying financial +statements. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. As such, +we assess impairment of our goodwill annually as of December 31 +or on an interim basis if events or circumstances +20 +Table of Contents +indicate that the fair value of the asset has decreased below +its carrying value. Goodwill impairment testing is performed at +the level of our reporting units. Our reporting units have been +determined to be the same as our operating segments. The +contract drilling segment and drilling and completion fluids +segments are the reporting units of the Company that have +goodwill. In connection with our annual assessment of potential +impairment of goodwill, we compare the fair value of the +reporting units with their carrying value. If the fair value +exceeds the carrying value, no impairment is indicated. If the +carrying value exceeds the fair value, we measure any impairment +of goodwill in that reporting unit by allocating the fair value +to the identifiable assets and liabilities of the reporting unit +based on their respective fair values. Any excess un-allocated +fair value would equal the implied fair value of goodwill, and +if that amount is below the carrying value of goodwill, an +impairment charge is recognized. +In connection with our annual goodwill impairment assessment +performed as of December 31, 2008, we performed an +impairment test of our contract drilling and drilling and +completion fluids reporting units. In light of the adverse +market conditions affecting our common stock price beginning in +the fourth quarter of 2008 and continuing into 2009, including a +significant decrease in the number of our rigs operating and a +significant decline in oil and natural gas commodity prices, we +utilized a discounted cash flow methodology to estimate the fair +values of our reporting units. In completing the first step of +our analysis, we used a three-year projection of discounted cash +flows, plus a terminal value determined using the constant +growth method to estimate the fair value of our reporting units. +In developing these fair value estimates, certain key +assumptions included an assumed discount rate of 13.99% for all +reporting units, an assumed long-term growth rate of 3.50% for +the contract drilling reporting unit and an assumed long-term +growth rate of 2.00% for the drilling and completion fluids +reporting unit. +Based on the results of the first step of the impairment test, +we concluded that no impairment was indicated in the contract +drilling reporting unit; however, an impairment was indicated in +our drilling and completion fluids reporting unit. In validating +this conclusion, we considered the results of our long-lived +asset impairment tests and performed sensitivity analyses of the +key assumptions used in deriving the respective fair values of +our reporting units. We performed the second step of the +analysis of our drilling and completion fluids reporting unit, +allocating the estimated fair value to the identifiable tangible +and intangible assets and liabilities of this reporting unit +based on their respective values. This allocation indicated no +residual value for goodwill, and accordingly we recorded an +impairment charge of $9.964 million in our December 31 +2008 statement of operations. +In the event that market conditions continue to deteriorate, we +may be required to record an impairment of goodwill in our +contract drilling reporting unit in the future and such +impairment may be material. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting. 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 total revenues. We recognize reimbursements received from +third parties for out-of-pocket expenses incurred as revenues +and account for these out-of-pocket expenses as direct costs. We +did not enter into any footage or turnkey contracts in the past +three years. +Use of estimates — The preparation of financial +statements in conformity with accounting principles generally +accepted in the United States of America requires management to +make certain estimates and assumptions that affect the reported +amounts of assets and liabilities and disclosures of contingent +assets and liabilities at the date of the financial statements +and the reported amounts of revenues and expenses during the +reporting period. Actual results could differ from such +estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation and depletion, +21 +Table of Contents +• +goodwill and long-lived asset impairments, +• +reserves for self-insured levels of insurance coverage, and +• +fair values of assets acquired 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. +Liquidity +and Capital Resources +As of December 31, 2008, we had working capital of +$339 million, including cash and cash equivalents of +$81.2 million. During 2008, our sources of cash flow +included: +• +$675 million from operating activities, +• +$11.6 million in proceeds from the disposal of property and +equipment, and +• +$41.8 million from the exercise of stock options and +related tax benefits associated with stock-based compensation. +During 2008, we used $92.9 million to pay dividends on our +common stock, $70.8 million to repurchase shares of our +common stock, $50.0 million to repay borrowings under our +line of credit and $449 million: +• +to build new drilling rigs, +• +to make capital expenditures for the betterment and +refurbishment of our drilling rigs, +• +to acquire and procure drilling equipment and facilities to +support our drilling operations, +• +to fund capital expenditures for our pressure pumping and +drilling and completion fluids segments, and +• +to fund investments in oil and natural gas properties on a +working interest basis. +We paid cash dividends during the year ended December 31, +2008 as follows: +Per Share +Total +(In thousands) +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +On February 11, 2009, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.05 per +share to be paid on March 31, 2009 to holders of record as +of March 12, 2009. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +On August 1, 2007, our Board of Directors approved a stock +buyback program (“2007 Program”), authorizing +purchases of up to $250 million of our common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2007, we purchased 3,308,850 shares +of our common stock under the 2007 Program at a cost of +approximately $70.4 million. During the year ended +December 31, 2008, we purchased 3,502,047 shares of +our common stock under the 2007 Program at a cost of +approximately $66.3 million. As of December 31, 2008, +we are authorized to purchase approximately $113 million of +our outstanding common stock under the 2007 Program. +We have an unsecured revolving line of credit with a maximum +borrowing capacity of $375 million which expires on +December 16, 2009. Interest is paid on outstanding balances +at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the +prime rate at our election. We are currently in the process of +evaluating our alternative courses of action with respect to the +upcoming maturity of this revolving line of credit. There can be +no assurance that we will be able to renew or replace the +existing revolving line of credit with similar terms, if at all. +As of +22 +Table of Contents +December 31, 2008, we had no borrowings outstanding under +our $375 million revolving line of credit. We had +$58.5 million in letters of credit outstanding under the +revolving line of credit at December 31, 2008, and as a +result we had available borrowing capacity of approximately +$316.5 million at such date. +We believe that the current level of cash, short-term +investments and borrowing capacity available under our current +revolving line of credit, together with cash expected to be +generated from operations, should be sufficient to meet our 2009 +capital needs. From time to time, acquisition opportunities are +evaluated. The timing, size or success of any acquisition and +the associated capital commitments are unpredictable. Should +opportunities for growth requiring capital arise, we believe we +would be able to satisfy these needs through a combination of +working capital, cash generated from operations, our existing +credit facility or additional debt or equity financing. However, +there can be no assurance that additional capital will be +available on reasonable terms, if at all. +Contractual +Obligations +The following table presents information with respect to our +contractual obligations as of December 31, 2008 (dollars in +thousands): +Payments Due by Period +Less Than 1 +More Than 5 +Total +Year +1-3 Years +3-5 Years +Years +Borrowings under line of credit(1) +$ +— +$ +— +$ +— +$ +— +$ +— +Commitments to purchase equipment(2) +268,934 +162,052 +106,882 +— +— +$ +268,934 +$ +162,052 +$ +106,882 +$ +— +$ +— +(1) +No borrowings were outstanding on our revolving line of credit +as of December 31, 2008. Our revolving line of credit +matures on December 16, 2009. +(2) +Represents commitments to purchase major equipment to be +delivered in 2009 and 2010 based on expected delivery dates. +Off-Balance +Sheet Arrangements +We had no off-balance sheet arrangements at December 31, +2008. +Results +of Operations +Comparison +of the years ended December 31, 2008 and 2007 +The following tables summarize operations by business segment +for the years ended December 31, 2008 and 2007: +Year Ended December 31, +Contract Drilling +2008 +2007 +% Change +(Dollars in thousands) +Revenues +$ +1,804,026 +$ +1,741,647 +3.6 +% +Direct operating costs +$ +1,038,327 +$ +963,150 +7.8 +% +Selling, general and administrative +$ +5,363 +$ +5,893 +(9.0 +)% +Depreciation +$ +229,311 +$ +213,812 +7.2 +% +Operating income +$ +531,025 +$ +558,792 +(5.0 +)% +Operating days +93,068 +89,095 +4.5 +% +Average revenue per operating day +$ +19.38 +$ +19.55 +(0.9 +)% +Average direct operating costs per operating day +$ +11.16 +$ +10.81 +3.2 +% +Average rigs operating +254 +244 +4.1 +% +Capital expenditures +$ +360,645 +$ +539,506 +(33.2 +)% +23 +Table of Contents +The demand for our contract drilling services is impacted by the +market price of natural gas and, to a lesser extent, oil. The +reactivation and construction of new land drilling rigs in the +United States in recent years has also contributed to an excess +capacity of land drilling rigs compared to demand. The average +market price of natural gas for each of the fiscal quarters and +full years in 2008 and 2007 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2007: +Average natural gas price(1) +$ +7.44 +$ +7.76 +$ +6.35 +$ +7.19 +$ +7.18 +2008: +Average natural gas price(1) +$ +8.92 +$ +11.74 +$ +9.28 +$ +6.60 +$ +9.13 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +Revenues and direct operating costs increased in 2008 compared +to 2007 primarily as a result of an increase in the number of +operating days. The increase in operating days was due to +increased demand caused by higher prices for natural gas during +most of 2008 compared to 2007. Average revenue per operating day +in 2008 was relatively flat compared to 2007. Average direct +operating costs per operating day increased in 2008 due to +incremental costs incurred to activate idle drilling rigs as +well as increases in labor, repairs and other related costs. +Significant capital expenditures have been incurred to build new +drilling rigs, to modify and upgrade our drilling rigs and to +acquire additional related equipment such as drill pipe, drill +collars, engines, fluid circulating systems, rig hoisting +systems and safety enhancement equipment. The increase in +depreciation expense was a result of the capital expenditures +discussed above. +Year Ended December 31, +Pressure Pumping +2008 +2007 +% Change +(Dollars in thousands) +Revenues +$ +217,494 +$ +202,812 +7.2 +% +Direct operating costs +$ +132,570 +$ +105,273 +25.9 +% +Selling, general and administrative +$ +23,305 +$ +18,971 +22.8 +% +Depreciation +$ +19,600 +$ +14,311 +37.0 +% +Operating income +$ +42,019 +$ +64,257 +(34.6 +)% +Total jobs +12,900 +14,094 +(8.5 +)% +Average revenue per job +$ +16.86 +$ +14.39 +17.2 +% +Average direct operating costs per job +$ +10.28 +$ +7.47 +37.6 +% +Capital expenditures +$ +61,289 +$ +47,582 +28.8 +% +In 2008, our customers increased their focus on the emerging +development of unconventional reservoirs in the Appalachian +Basin and the larger jobs associated therewith. As a result of +this focus on unconventional reservoirs, we experienced a +decrease in smaller traditional pressure pumping jobs, which +resulted in an overall decrease in the number of total jobs. +Revenues and direct operating costs increased as a result of an +increase in the average revenue and average direct operating +costs per job. Increased average revenue per job was due to an +increase in larger jobs being driven by demand for services +associated with unconventional reservoirs as discussed above. +Average direct operating costs per job increased as a result of +increases in compensation, maintenance and the cost of materials +used in our operations, as well as an increase in larger jobs, +which require significantly more materials to complete. In +anticipation of increased activity associated with the +unconventional reservoirs in the Appalachian Basin, we have +added facilities, equipment and personnel over the past two +years. Delays in the development of these reservoirs have caused +a slower increase in customer activity than we had expected, +negatively impacting the profitability of this business. +Selling, general and administrative expense increased primarily +as a result of expenses to support the expanding operations of +this segment. Significant capital expenditures have been +incurred to add capacity, expand our areas of operation and +modify and upgrade existing equipment. The increase in +depreciation expense is a result of the capital expenditures +discussed above. +24 +Table of Contents +Year Ended December 31, +Drilling and Completion Fluids +2008 +2007 +% Change +(Dollars in thousands) +Revenues +$ +145,246 +$ +128,098 +13.4 +% +Direct operating costs +$ +126,900 +$ +108,752 +16.7 +% +Selling, general and administrative +$ +10,110 +$ +9,958 +1.5 +% +Depreciation +$ +2,830 +$ +2,860 +(1.0 +)% +Goodwill impairment +$ +9,964 +$ +— +N/A +% +Operating income (loss) +$ +(4,558 +) +$ +6,528 +N/A +% +Capital expenditures +$ +3,467 +$ +3,082 +12.5 +% +Revenues increased in 2008 compared to 2007 due to increased +sales both on land and offshore in the Gulf of Mexico, as well +as increased pricing for certain products. Direct operating +costs increased due to increased sales as well as increases in +the cost of raw materials, including barite ore. Direct +operating costs in 2008 also include approximately $940,000 in +losses associated with damage suffered as a result of +hurricanes. Direct operating costs in 2007 include a reduction +of approximately $1.9 million related to a recovery +received on an insurance claim. In connection with our annual +assessment of the potential impairment of goodwill as of +December 31, 2008, we estimated the fair value of our +drilling and completion fluids reporting unit based on +discounted expected cash flows. Based on this assessment we +determined that all goodwill of this reporting unit was impaired +and a charge was recognized in the fourth quarter of 2008. No +impairment of goodwill was indicated in our previous annual +assessment as of December 31, 2007. As of December 31, +2008, our drilling and completion fluids segment has no +remaining goodwill. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2008 +2007 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +42,360 +$ +41,637 +1.7 +% +Direct operating costs +$ +12,793 +$ +10,864 +17.8 +% +Selling, general and administrative +$ +— +$ +2,365 +(100.0 +)% +Depreciation, depletion and impairment +$ +15,856 +$ +17,410 +(8.9 +)% +Operating income +$ +13,711 +$ +10,998 +24.7 +% +Capital expenditures +$ +22,981 +$ +17,516 +31.2 +% +Average net daily oil production (Bbls) +801 +971 +(17.5 +)% +Average net daily gas production (Mcf) +3,755 +4,996 +(24.8 +)% +Average oil sales price (per Bbl) +$ +98.70 +$ +68.82 +43.4 +% +Average gas sales price (per Mcf) +$ +9.77 +$ +7.37 +32.6 +% +Revenues increased due to higher average sales prices of oil and +natural gas. This increase was partially offset by a decrease in +the average net daily production of oil and natural gas and by +the elimination of well operations revenue due to the sale in +the fourth quarter of 2007 of the operating responsibilities +associated with oil and natural gas wells. Average net daily oil +and natural gas production decreased primarily due to the sale +of properties in 2007 and production declines. Direct operating +costs increased due to an increase in seismic expenses as well +as increased production taxes and other production costs. +Selling, general and administrative expense decreased in 2008 +due to the sale of the operating responsibilities mentioned +above and the resulting elimination of headcount in this +segment. Depreciation, depletion and impairment expense in 2008 +includes approximately $4.4 million incurred to impair +certain oil and natural gas properties compared to approximately +$3.9 million incurred to impair certain oil and natural gas +properties in 2007. Depletion expense decreased approximately +$1.9 million primarily due to the sale of certain +properties in 2007. +25 +Table of Contents +Year Ended December 31, +Corporate and Other +2008 +2007 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +29,412 +$ +27,436 +7.2 +% +Depreciation +$ +834 +$ +813 +2.6 +% +Other operating expenses +$ +4,350 +$ +2,550 +70.6 +% +Embezzlement recoveries +$ +— +$ +(43,955 +) +(100.0 +)% +Net loss (gain) on asset disposals/retirements +$ +6,071 +$ +(16,545 +) +N/A +% +Interest income +$ +1,555 +$ +2,355 +(34.0 +)% +Interest expense +$ +639 +$ +2,187 +(70.8 +)% +Other income +$ +502 +$ +363 +38.3 +% +Capital expenditures +$ +511 +$ +— +N/A +% +Selling, general and administrative expense increased primarily +as a result of additional compensation expense and an increase +in payroll tax expense associated with the exercise of stock +options during 2008. Other operating expenses increased due to +an increase in bad debt expense of $1.8 million. In 2008, +we retired 22 drilling rigs out of our fleet and transferred +usable components with a net book value of $13.4 million to +our yards to be used as spare equipment. Losses on the +retirement of components that were not transferred to the yards +were approximately $10.4 million, and we recognized gains +on the disposal of other assets of approximately +$4.3 million in 2008. In 2007, we sold certain oil and +natural gas properties resulting in a gain of $21.6 million +which was partially offset by approximately $5.1 million in +losses associated with the disposal of other assets. Gains and +losses on the disposal or retirement of assets are considered as +part of our corporate activities because such transactions +relate to decisions of our executive management regarding +corporate strategy. +In November 2005, we discovered that our former Chief Financial +Officer, Jonathan D. Nelson (“Nelson”), had +fraudulently diverted approximately $77.5 million in +Company funds for his own benefit during the period from 1998 +through 2005. As a result, the Audit Committee of the Board of +Directors commenced an investigation into Nelson’s +activities and retained independent counsel and independent +forensic accountants to assist with the investigation. Nelson +has been sentenced and is serving a term of imprisonment arising +out of his embezzlement. A receiver was appointed to take +control of and liquidate the assets of Nelson. In May 2007, the +court approved a plan of distribution for the assets recovered +by the receiver. We recovered a total of approximately +$44.5 million pursuant to the approved plan, and we +recognized this recovery in our consolidated statement of income +in 2007, net of professional fees incurred as a result of the +embezzlement. +Comparison +of the years ended December 31, 2007 and 2006 +The following tables summarize operations by business segment +for the years ended December 31, 2007 and 2006: +Year Ended December 31, +Contract Drilling +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +1,741,647 +$ +2,169,370 +(19.7 +)% +Direct operating costs +$ +963,150 +$ +1,002,001 +(3.9 +)% +Selling, general and administrative +$ +5,893 +$ +7,313 +(19.4 +)% +Depreciation +$ +213,812 +$ +168,607 +26.8 +% +Operating income +$ +558,792 +$ +991,449 +(43.6 +)% +Operating days +89,095 +108,192 +(17.7 +)% +Average revenue per operating day +$ +19.55 +$ +20.05 +(2.5 +)% +Average direct operating costs per operating day +$ +10.81 +$ +9.26 +16.7 +% +Average rigs operating +244 +296 +(17.6 +)% +Capital expenditures +$ +539,506 +$ +531,087 +1.6 +% +26 +Table of Contents +The demand for our contract drilling services is impacted by the +market price of natural gas and, to a lesser extent, oil. The +reactivation and construction of new land drilling rigs in the +United States in recent years has also contributed to excess +capacity compared to demand. Additionally, drilling activity in +Canada decreased significantly in 2007 compared to 2006. As a +result, our average rigs operating declined to 244 in 2007 from +296 in 2006. The average market price of natural gas for each of +the fiscal quarters and full years in 2007 and 2006 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2006: +Average natural gas price(1) +$ +7.93 +$ +6.74 +$ +6.26 +$ +6.87 +$ +6.94 +2007: +Average natural gas price(1) +$ +7.44 +$ +7.76 +$ +6.35 +$ +7.19 +$ +7.18 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +Revenues in 2007 decreased as compared to 2006 as a result of +decreases in the number of operating days and in the average +revenues per operating day. Direct operating costs in 2007 +decreased as compared to 2006 as a result of the decreased +number of operating days, largely offset by an increase in the +average direct operating costs per operating day. The increase +in average direct operating costs per day resulted primarily +from increased compensation costs and an increase in the cost of +maintenance for our drilling rigs. Operating days, average rigs +operating and average revenue per operating day decreased in +2007 as a result of decreased demand for our contract drilling +services resulting from the excess capacity discussed above. +Selling, general and administrative expense decreased primarily +as a result of the transfer of certain administrative staff to +our corporate segment. Significant capital expenditures have +been incurred in both 2007 and 2006 to activate additional +drilling rigs, to modify and upgrade our drilling rigs and to +acquire additional related equipment such as drill pipe, drill +collars, engines, fluid circulating systems, rig hoisting +systems and safety enhancement equipment. The increase in +depreciation expense is a result of the capital expenditures +discussed above. +Year Ended December 31, +Pressure Pumping +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +202,812 +$ +145,671 +39.2 +% +Direct operating costs +$ +105,273 +$ +77,755 +35.4 +% +Selling, general and administrative +$ +18,971 +$ +13,185 +43.9 +% +Depreciation +$ +14,311 +$ +9,896 +44.6 +% +Operating income +$ +64,257 +$ +44,835 +43.3 +% +Total jobs +14,094 +11,650 +21.0 +% +Average revenue per job +$ +14.39 +$ +12.50 +15.1 +% +Average direct operating costs per job +$ +7.47 +$ +6.67 +12.0 +% +Capital expenditures +$ +47,582 +$ +41,262 +15.3 +% +Revenues and direct operating costs increased as a result of the +increased number of jobs, as well as an increase in the average +revenue and average direct operating costs per job. The increase +in jobs was attributable to increased demand for our services +and increased operating capacity. Increased average revenue per +job was due to increased pricing for our services and an +increase in the number of larger jobs being driven by demand for +services associated with unconventional reservoirs in the +Appalachian basin. Average direct operating costs per job +increased as a result of increases in compensation, maintenance +and the cost of materials used in our operations, as well as an +increase in the number of larger jobs. Selling, general and +administrative expense increased primarily as a result of +expenses to support the expanding operations of the pressure +pumping segment. Significant capital expenditures have been +incurred in both 2007 and 2006 to add capacity, expand our areas +of operation and modify and upgrade existing equipment. The +increase in depreciation expense is a result of the capital +expenditures discussed above. +27 +Table of Contents +Year Ended December 31, +Drilling and Completion Fluids +2007 +2006 +% Change +(Dollars in thousands) +Revenues +$ +128,098 +$ +192,358 +(33.4 +)% +Direct operating costs +$ +108,752 +$ +150,372 +(27.7 +)% +Selling, general and administrative +$ +9,958 +$ +10,521 +(5.4 +)% +Depreciation +$ +2,860 +$ +2,706 +5.7 +% +Operating income +$ +6,528 +$ +28,759 +(77.3 +)% +Capital expenditures +$ +3,082 +$ +4,222 +(27.0 +)% +Revenues and direct operating costs decreased as a result of a +decrease in the number of large jobs offshore in the Gulf of +Mexico caused primarily by a slowdown in drilling activity +during 2007 as compared to 2006. +Year Ended December 31, +2007 +2006 +% Change +Oil and Natural Gas Production and Exploration +(Dollars in thousands, except commodity prices) +Revenues +$ +41,637 +$ +39,187 +6.3 +% +Direct operating costs +$ +10,864 +$ +13,374 +(18.8 +)% +Selling, general and administrative +$ +2,365 +$ +2,785 +(15.1 +)% +Depreciation, depletion and impairment +$ +17,410 +$ +14,368 +21.2 +% +Operating income +$ +10,998 +$ +8,660 +27.0 +% +Capital expenditures +$ +17,516 +$ +21,198 +(17.4 +)% +Average net daily oil production (Bbls) +971 +983 +(1.2 +)% +Average net daily gas production (Mcf) +4,996 +5,143 +(2.9 +)% +Average oil sales price (per Bbl) +$ +68.82 +$ +63.83 +7.8 +% +Average gas sales price (per Mcf) +$ +7.37 +$ +6.82 +8.1 +% +Revenues increased due to an increase in the average sales price +of both oil and natural gas in 2007 compared to 2006. Average +net daily oil and natural gas production decreased in 2007 +primarily due to the sale of certain properties in the first +half of 2007. The decrease in direct operating costs is +primarily due to a decrease of approximately $3.0 million +in costs associated with the abandonment of exploratory wells in +2007 compared to 2006. Selling, general and administrative +expenses decreased in 2007 primarily due to the transfer in the +fourth quarter of the operating responsibilities associated with +oil and natural gas wells resulting in reduced headcount in our +oil and natural gas production and exploration segment. +Depreciation, depletion and impairment expense in 2007 includes +approximately $3.9 million incurred to impair certain oil +and natural gas properties compared to approximately +$5.0 million incurred to impair certain oil and natural gas +properties in 2006. Depletion expense increased approximately +$4.2 million primarily due to the completion of new wells +in 2007. +Year Ended December 31, +Corporate and Other +2007 +2006 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +27,436 +$ +21,261 +29.0 +% +Depreciation +$ +813 +$ +793 +2.5 +% +Other operating expenses +$ +2,550 +$ +5,585 +(54.3 +)% +Embezzlement costs (recoveries) +$ +(43,955 +) +$ +3,081 +N/A +% +Net loss (gain) on asset disposals/retirements +$ +(16,545 +) +$ +3,819 +N/A +% +Interest income +$ +2,355 +$ +5,925 +(60.3 +)% +Interest expense +$ +2,187 +$ +1,602 +36.5 +% +Other income +$ +363 +$ +347 +4.6 +% +Capital expenditures +$ +— +$ +150 +(100.0 +)% +Selling, general and administrative expense increased primarily +as a result of compensation expense related to transfers of +certain administrative staff from our drilling segment to our +corporate segment as well as increases in +28 +Table of Contents +stock-based compensation expense. Other operating expenses +decreased due to a decrease in bad debt expense of +$2.9 million. In 2007, we sold certain oil and natural gas +properties resulting in a gain of $21.6 million This gain +was reduced by approximately $5.1 million in losses +associated with the disposal of other assets. Gains and losses +on the disposal or retirement of assets are considered as part +of our corporate activities due to the fact that such +transactions relate to decisions of the executive management +group regarding corporate strategy. Embezzlement costs +(recoveries) in 2007 includes a recovery of $44.5 million +reduced by professional fees incurred as a result of the +embezzlement involving our former Chief Financial Officer. +Embezzlement costs (recoveries) in 2006 include professional +fees incurred as a result of the embezzlement reduced by +insurance proceeds of $2.3 million. +Income +Taxes +Year Ended December 31, +2008 +2007 +2006 +(Dollars in thousands) +Income before income tax +$ +542,948 +$ +670,807 +$ +1,043,834 +Income tax expense +195,879 +232,168 +371,267 +Effective tax rate +36.1 +% +34.6 +% +35.6 +% +The effective tax rate is a result of a Federal rate of 35.0% +adjusted as follows: +2008 +2007 +2006 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.7 +1.4 +1.4 +Permanent differences +(0.4 +) +(1.6 +) +(0.8 +) +Other, net +(0.2 +) +(0.2 +) +0.0 +Effective tax rate +36.1 +% +34.6 +% +35.6 +% +The permanent differences indicated above are largely +attributable to our Domestic Production Activities deduction, +partially offset in 2008 by the non-deductible goodwill +impairment recognized in our drilling and completion fluids +segment. The Domestic Production Activities Deduction was +enacted as part of the American Jobs Creation Act of 2004 (as +revised by the Emergency Economic Stabilization Act of 2008, the +“Act”) and is effective for taxable years after +December 31, 2004. The Act allows a deduction of 3% in 2006 +and 6% in both 2007 and 2008 on the lesser of qualified +production activities income or taxable income. +We record deferred Federal income taxes based primarily on the +temporary differences between the book and tax bases of our +assets. Deferred tax assets and liabilities are measured using +enacted tax rates expected to apply to taxable income in the +year in which those temporary differences are expected to be +settled. As a result of fully recognizing the benefit of our +deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We incurred a deferred tax expense +of approximately $66.0 million in 2008, $38.3 million +in 2007 and a deferred tax benefit of approximately +$4.1 million in 2006. +Volatility +of Oil and Natural Gas Prices and its Impact on +Operations +Our revenue, profitability, and rate of growth are substantially +dependent upon prevailing prices for natural gas and, to a +lesser extent, oil. For many years, oil and natural gas prices +and markets have been extremely volatile. Prices are affected by +market supply and demand factors as well as international +military, political and economic conditions, and the ability of +OPEC to set and maintain production and price targets. All of +these factors are beyond our control. During 2008, the monthly +average market price of natural gas peaked in June at $13.06 per +Mcf before rapidly declining to an average of $5.99 per Mcf in +December. In January 2009, the average market price of natural +gas declined further to $5.40 per Mcf. This has resulted in our +customers significantly reducing their drilling activities +beginning in the fourth quarter of 2008 and continuing into +2009. This reduction in demand combined with the reactivation +and construction of new land drilling rigs in the United States +during the last several years has resulted in excess capacity +compared to demand. As a result of these factors, our average +number of rigs operating has recently declined significantly. We +expect oil and natural gas prices to continue to be volatile and +to affect our +29 +Table of Contents +financial condition, operations and ability to access sources of +capital. Continued low market prices for natural gas will likely +result in further decreases in demand for our drilling rigs and +adversely affect our operating results. +The North American land drilling industry has experienced +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 difficulty sustaining profit margins during the downturn +periods. +Impact of +Inflation +Inflation has not had a significant impact on our operations +during the three years in the period ended December 31, +2008. We believe that inflation will not have a significant +near-term impact on our financial position. +Recently +Issued Accounting Standards +In September 2006, the FASB issued Statement No. 157, +Fair Value Measurements (“FAS 157”). +FAS 157 defines fair value, establishes a framework for +measuring fair value in generally accepted accounting +principles, and expands disclosures about fair value +measurement. The initial application of FAS 157 is limited +to financial assets and liabilities and became effective on +January 1, 2008 for us. The impact of the initial +application of FAS 157 was not material. On January 1, +2009, we adopted FAS 157 on a prospective basis for +non-financial assets and liabilities that are not measured at +fair value on a recurring basis. The application of FAS 157 +to our non-financial assets and liabilities will primarily be +limited to assets acquired and liabilities assumed in a business +combination, asset retirement obligations and asset impairments, +including goodwill and long-lived assets. This application of +FAS 157 is not expected to have a material impact to us. +In December 2007, the FASB issued Statement No. 141(R), +Business Combinations (“FAS 141(R)”) and +Statement No. 160, Noncontrolling Interests in +Consolidated Financial Statements, an amendment of ARB +No. 51 (“FAS 160”). FAS 141(R) is a +revision of Statement No. 141, Business +Combinations , and calls for significant changes from current +practice in accounting for business combinations. +FAS 141(R) is effective for business combinations for which +the acquisition date is on or after the beginning of the first +annual reporting period beginning on or after December 15, +2008. FAS 160 amends ARB 51 to establish accounting and +reporting standards for the non-controlling interest in a +subsidiary and for the deconsolidation of a subsidiary. +FAS 160 is effective for fiscal years beginning on or after +December 15, 2008. Both FAS 141(R) and FAS 160 +became effective for us on January 1, 2009. The application +of FAS 141(R) and FAS 160 are not expected to have a +material impact to us. +In June 2008, the FASB issued FASB Staff Position +No. EITF 03-6-1, +Determining Whether Instruments Granted in Share-Based +Payment Transactions Are Participating Securities (“FSP +EITF 03-6-1”). +FSP +EITF 03-6-1 +clarifies that share-based payment awards that entitle their +holders to receive non-forfeitable dividends before vesting +should be considered participating securities and, as such, +should be included in the calculation of basic +earnings-per-share +using the two-class method. Certain of our share-based payment +awards entitle the holders to receive non-forfeitable dividends +and the application of the provisions of FSP +EITF 03-6-1 +may have the effect of reducing basic and diluted +earnings-per-share +by an immaterial amount. FSP +EITF 03-6-1 +is effective for financial statements issued for fiscal years +beginning after December 15, 2008, as well as interim +periods within those years. Once effective, all prior-period +earnings-per-share +data presented must be adjusted retrospectively to conform with +the provisions of FSP +EITF 03-6-1. +FSP +EITF 03-6-1 +will be effective for us beginning in the quarter ending +March 31, 2009, and early application is not permitted. The +adoption of FSP +EITF 03-6-1 +is not expected to have a material impact to us. +Item 7A. +Quantitative +and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk +associated with any borrowings that we have under our revolving +credit facility. The revolving credit facility calls for +periodic interest payments at a floating rate ranging from LIBOR +plus 0.625% to 1.0% or at the prime rate. The applicable rate +above LIBOR is based upon our debt to capitalization ratio. As +of December 31, 2008, we had no borrowings outstanding +under our credit facility. +30 +Table of Contents +We conduct a portion of our business in Canadian dollars through +our Canadian land-based drilling operations. The exchange rate +between Canadian dollars and U.S. dollars has fluctuated +during the last several years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and +earnings of our Canadian operations will be reduced and the +value of our Canadian net assets will decline when they are +translated to U.S. dollars. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +Item 8. +Financial +Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the +end of Part IV hereof beginning at +page F-1, +Index to Consolidated Financial Statements, and are incorporated +herein by this reference. +Item 9. +Changes +in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2008, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO +and CFO, as appropriate to allow timely decisions regarding +required disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2008, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2008. +The effectiveness of our internal control over financial +reporting as of December 31, 2008 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and is incorporated by reference into Item 8 +of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. +Item 9B. +Other +Information +None. +31 +Table of Contents +PART III +The information required by Part III is omitted from this +Report because we expect to file a definitive proxy statement +(the “Proxy Statement”) pursuant to +Regulation 14A of the Securities Exchange Act of 1934 no +later than 120 days after the end of the fiscal year +covered by this Report and certain information included therein +is incorporated herein by reference. +Item 10. +Directors, +Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 11. +Executive +Compensation. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 12. +Security +Ownership of Certain Beneficial Owners and Management and +Related Stockholder Matters. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +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. +32 +Table of Contents +PART IV +Item 15. +Exhibits +and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 +of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts +is filed herewith on +page S-1. +All other financial statement schedules have been omitted +because they are not applicable or the information required +therein is included elsewhere in the financial statements or +notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by +reference herein. +3 +.1 +Restated Certificate of Incorporation, as amended (filed August +9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on +Form 10-Q for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended +June 30, 2004 and incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q +for the quarterly period ended June 30, 2007 and incorporated +herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & Trust Company +(filed January 14, 1997 as Exhibit 2 to the Company’s +Registration Statement on Form 8-A and incorporated herein by +reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended +September 30, 2001 and incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See Exhibits +3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners III, +L.P. (filed March 19, 2002 as Exhibit 4.3 to the Company’s +Annual Report on Form 10-K for the fiscal year ended December +31, 2001 and incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as +amended (filed March 13, 1998 as Exhibit 10.1 to the +Company’s Registration Statement on Form S-8 (File No. +333-47917) and incorporated herein by reference).* +10 +.3 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post +Effective Amendment No. 1 to the Company’s Registration +Statement on Form S-8 (File No. 333-60470) and incorporated +herein by reference).* +10 +.4 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the +Company’s Quarterly Report on Form 10-Q for the quarterly +period ended June 30, 2003 and incorporated herein by +reference).* +10 +.5 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit +10.7 to the Company’s Quarterly Report on Form 10-Q for the +quarterly period ended June 30, 2004 and incorporated herein by +reference).* +10 +.6 +Amended and Restated Patterson-UTI Energy, Inc. Non-Employee +Director Stock Option Plan(filed July 28, 2003 as Exhibit +4.8 to the Company’s Quarterly Report on Form 10-Q for the +quarterly period ended June 30, 2003 and incorporated herein by +reference).* +10 +.7 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 to +Post-Effective Amendment No. 1 to the Company’s +Registration Statement on Form S-8 (File No. 333-60466) and +incorporated herein by reference).* +33 +Table of Contents +10 +.8 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s Current +Report on Form 8-K, and incorporated herein by reference).* +10 +.9 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the +Company’s Current Report on Form 8-K and incorporated +herein by reference). +10 +.10 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 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 (filed +August 9, 2004 as Exhibit 10.1 to the Company’s Quarterly +Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and incorporated +herein by reference).* +10 +.12 +Restricted Stock Award Agreement dated April 28, 2004 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed August +9, 2004 as Exhibit 10.2 to the Company’s Quarterly Report +on Form 10-Q for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.13 +Restricted Stock Award Agreement dated April 28, 2004 between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed August 9, +2004 as Exhibit 10.4 to the Company’s Quarterly Report on +Form 10-Q for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Restricted Stock Award Agreement dated April 28, 2004 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +August 9, 2004 as Exhibit 10.6 to the Company’s Quarterly +Report on Form 10-Q for the quarterly period ended June 30, 2004 +and incorporated herein by reference).* +10 +.15 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between Patterson-UTI +Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as +Exhibit 10.2 to the Company’s Annual Report on Form 10-K +for the year ended December 31, 2003 and incorporated herein by +reference).* +10 +.16 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott +(filed on September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on Form 8-K, and incorporated +herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between Patterson-UTI +Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as +Exhibit 10.5 to the Company’s Annual Report on Form 10-K +for the year ended December 31, 2003 and incorporated herein by +reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between Patterson-UTI +Energy, Inc. and John E. Vollmer III (filed on February 4, +2004 as Exhibit 10.7 to the Company’s Annual Report on Form +10-K for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.19 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, Inc. +with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.20 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. +Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, +Terry H. Hunt, Kenneth R. Peak, Charles O. Buckner, +John E. Vollmer III, William L. Moll, Jr. and Gregory W. Pipkin +(filed April 28, 2004 as Exhibit 10.11 to the Company’s +Annual Report on Form 10-K, as amended, for the year ended +December 31, 2003 and incorporated herein by reference).* +10 +.21 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the Company’s Current +Report on Form 8-K and incorporated herein by reference).* +10 +.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between Patterson-UTI +Energy, Inc. and Douglas J. Wall (filed September 4, 2007 as +Exhibit 10.2 to the Company’s Current Report on Form 8-K +and incorporated herein by reference).* +34 +Table of Contents +10 +.23 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between Patterson-UTI +Energy, Inc. and William L. Moll, Jr. (filed November 5, 2007 as +Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the +Company’s Quarterly Report on Form 10-Q for the quarterly +period ended September 30, 2007 and incorporated herein by +reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the +Company’s Quarterly Report on Form 10-Q for the quarterly +period ended September 30, 2007 and incorporated herein by +reference).* +10 +.26 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 as Exhibit +10.10 to the Company’s Quarterly Report on Form 10-Q for +the quarterly period ended September 30, 2007 and incorporated +herein by reference).* +10 +.27 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the +Company’s Quarterly Report on Form 10-Q for the quarterly +period ended September 30, 2007 and incorporated herein by +reference).* +10 +.28 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and William L. Moll, Jr., entered +into November 1, 2007 (filed November 5, 2007 as Exhibit 10.12 +to the Company’s Quarterly Report on Form 10-Q for the +quarterly period ended September 30, 2007 and incorporated +herein by reference).* +10 +.29 +Credit Agreement dated as of December 17, 2004 among +Patterson-UTI Energy, Inc., as the Borrower, Bank of America, +N.A., as administrative agent, L/C Issuer and a Lender and the +other lenders and agents party thereto (filed on December 23, +2004 as Exhibit 10.1 to the Company’s Current Report on +Form 8-K and incorporated herein by reference). +10 +.30 +Commitment Increase and Joinder Agreement, dated as of August 2, +2006, by and among Patterson-UTI Energy, Inc., the guarantors +party thereto, the lenders party thereto, and Bank of America, +N.A. as Administrative Agent, L/C Issuer and Lender (filed +August 21, 2006 as Exhibit 10.1 to the Company’s Current +Report on Form 8-K and incorporated herein by reference). +10 +.31 +Letter Agreement dated February 6, 2006 between Patterson-UTI +Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as +Exhibit 10.25 to the Company’s Annual Report on Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics +for Senior Financial Executives (filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to Rule +13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as +amended. +31 +.2 +Certification of Chief Financial Officer pursuant to Rule +13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as +amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. +35 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of Independent Registered Public +Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of +December 31, 2008 and 2007 +F-3 +Consolidated Statements of Income for the years +ended December 31, 2008, 2007 and 2006 +F-4 +Consolidated Statements of Changes In +Stockholders’ Equity for the years ended December 31, +2008, 2007 and 2006 +F-5 +Consolidated Statements of Cash Flows for the +years ended December 31, 2008, 2007 and 2006 +F-6 +Notes to Consolidated Financial Statements +F-7 +Financial Statement Schedule +S-1 +EX-21.1 +EX-23.1 +EX-31.1 +EX-31.2 +EX-32.1 +F-1 +Table of Contents +Report of +Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of +Patterson-UTI Energy, Inc.: +In our opinion, the consolidated financial statements listed in +the accompanying index present fairly, in all material respects, +the financial position of Patterson-UTI Energy, Inc. and its +subsidiaries at December 31, 2008 and 2007, and the results +of their operations and their cash flows for each of the three +years in the period ended December 31, 2008 in conformity +with accounting principles generally accepted in the United +States of America. In addition, in our opinion, the financial +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 financial statements. Also in our +opinion, the Company maintained, in all material respects, +effective internal control over financial reporting as of +December 31, 2008, based on criteria established in +Internal Control — Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). The Company’s management is responsible +for these financial statements and financial statement schedule, +for maintaining effective internal control over financial +reporting and for its assessment of the effectiveness of +internal control over financial reporting, included in +Management’s Report on Internal Control over Financial +Reporting appearing under Item 9A. Our responsibility is to +express opinions on these financial statements, on the financial +statement schedule, and on the Company’s internal control +over financial reporting based on our integrated audits. We +conducted our audits in accordance with the standards of the +Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audits to obtain +reasonable assurance about whether the financial statements are +free of material misstatement and whether effective internal +control over financial reporting was maintained in all material +respects. Our audits of the financial statements included +examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by +management, and evaluating the overall financial statement +presentation. Our audit of internal control over financial +reporting included obtaining an understanding of internal +control over financial reporting, assessing the risk that a +material weakness exists, and testing and evaluating the design +and operating effectiveness of internal control based on the +assessed risk. Our audits also included performing such other +procedures as we considered necessary in the circumstances. We +believe that our audits provide a reasonable basis for our +opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 18, 2009 +F-2 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2008 +2007 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +81,223 +$ +17,434 +Accounts receivable, net of allowance for doubtful accounts of +$9,330 and $10,014 at December 31, 2008 and 2007, +respectively +414,531 +373,279 +Federal and state income taxes receivable +10,175 +— +Inventory +41,999 +44,416 +Deferred tax assets, net +35,928 +35,370 +Other +57,518 +52,286 +Total current assets +641,374 +522,785 +Property and equipment, net +1,937,112 +1,841,404 +Goodwill +86,234 +96,198 +Deposits on equipment purchases +43,944 +— +Other +4,153 +4,812 +Total assets +$ +2,712,817 +$ +2,465,199 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +169,958 +$ +156,916 +Federal and state income taxes payable +— +1,458 +Accrued expenses +132,655 +136,834 +Total current liabilities +302,613 +295,208 +Borrowings under line of credit +— +50,000 +Deferred tax liabilities, net +277,717 +219,490 +Other +5,545 +4,471 +Total liabilities +585,875 +569,169 +Commitments and contingencies (see Note 8) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 180,192,093 and 177,385,808 issued and 153,094,803 and +153,942,800 outstanding at December 31, 2008 and 2007, +respectively +1,801 +1,773 +Additional paid-in capital +765,512 +703,581 +Retained earnings +1,970,824 +1,716,620 +Accumulated other comprehensive income +5,774 +20,207 +Treasury stock, at cost, 27,097,290 shares and +23,443,008 shares at December 31, 2008 and 2007, +respectively +(616,969 +) +(546,151 +) +Total stockholders’ equity +2,126,942 +1,896,030 +Total liabilities and stockholders’ equity +$ +2,712,817 +$ +2,465,199 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF INCOME +Year Ended December 31, +2008 +2007 +2006 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,804,026 +$ +1,741,647 +$ +2,169,370 +Pressure pumping +217,494 +202,812 +145,671 +Drilling and completion fluids +145,246 +128,098 +192,358 +Oil and natural gas +42,360 +41,637 +39,187 +2,209,126 +2,114,194 +2,546,586 +Operating costs and expenses: +Contract drilling +1,038,327 +963,150 +1,002,001 +Pressure pumping +132,570 +105,273 +77,755 +Drilling and completion fluids +126,900 +108,752 +150,372 +Oil and natural gas +12,793 +10,864 +13,374 +Goodwill impairment +9,964 +— +— +Depreciation, depletion and other impairment +268,431 +249,206 +196,370 +Selling, general and administrative +68,190 +64,623 +55,065 +Embezzlement costs (recoveries) +— +(43,955 +) +3,081 +Net loss (gain) on asset disposals/retirements +6,071 +(16,545 +) +3,819 +Other operating expenses +4,350 +2,550 +5,585 +1,667,596 +1,443,918 +1,507,422 +Operating income +541,530 +670,276 +1,039,164 +Other income (expense): +Interest income +1,555 +2,355 +5,925 +Interest expense +(639 +) +(2,187 +) +(1,602 +) +Other +502 +363 +347 +1,418 +531 +4,670 +Income before income taxes and cumulative effect of change in +accounting principle +542,948 +670,807 +1,043,834 +Income tax expense (benefit): +Current +129,840 +193,897 +375,373 +Deferred +66,039 +38,271 +(4,106 +) +195,879 +232,168 +371,267 +Income before cumulative effect of change in accounting principle +347,069 +438,639 +672,567 +Cumulative effect of change in accounting principle, net of +related income tax expense of $398 +— +— +687 +Net income +$ +347,069 +$ +438,639 +$ +673,254 +Income before cumulative effect of change in accounting +principle per common share: +Basic +$ +2.26 +$ +2.83 +$ +4.07 +Diluted +$ +2.24 +$ +2.79 +$ +4.02 +Net income per common share: +Basic +$ +2.26 +$ +2.83 +$ +4.08 +Diluted +$ +2.24 +$ +2.79 +$ +4.02 +Weighted average number of common shares outstanding: +Basic +153,379 +154,755 +165,159 +Diluted +154,717 +156,997 +167,413 +Cash dividends per common share +$ +0.60 +$ +0.44 +$ +0.28 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Deferred +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Compensation +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2005 +175,909 +$ +1,759 +$ +672,151 +$ +(9,287 +) +$ +719,113 +$ +8,565 +$ +(25,290 +) +$ +1,367,011 +Comprehensive income: +Net income +— +— +— +— +673,254 +— +— +673,254 +Foreign currency translation adjustment, (net of tax of $6) +— +— +— +— +— +(175 +) +— +(175 +) +Total comprehensive income +— +— +— +— +673,254 +(175 +) +— +673,079 +Elimination of deferred compensation due to change in accounting +principle +— +— +(9,287 +) +9,287 +— +— +— +— +Issuance of restricted stock +613 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(47 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +181 +2 +1,944 +— +— +— +— +1,946 +Tax benefit related to stock-based compensation +— +— +1,087 +— +— +— +— +1,087 +Stock-based compensation, net of cumulative effect of change in +accounting principle +— +— +15,179 +— +— +— +— +15,179 +Payment of cash dividend +— +— +— +— +(45,825 +) +— +— +(45,825 +) +Purchase of treasury stock +— +— +— +— +— +— +(450,011 +) +(450,011 +) +Balance, December 31, 2006 +176,656 +1,766 +681,069 +— +1,346,542 +8,390 +(475,301 +) +1,562,466 +Comprehensive income: +Net income +— +— +— +— +438,639 +— +— +438,639 +Foreign currency translation adjustment, (net of tax of $6,755) +— +— +— +— +— +11,817 +— +11,817 +Total comprehensive income +— +— +— +— +438,639 +11,817 +— +450,456 +Issuance of restricted stock +601 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(101 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +230 +2 +2,048 +— +— +— +— +2,050 +Tax benefit related to stock-based compensation +— +— +1,105 +— +— +— +— +1,105 +Stock-based compensation +— +— +19,364 +— +— +— +— +19,364 +Payment of cash dividend +— +— +— +— +(68,561 +) +— +— +(68,561 +) +Purchase of treasury stock +— +— +— +— +— +— +(70,850 +) +(70,850 +) +Balance, December 31, 2007 +177,386 +1,773 +703,581 +— +1,716,620 +20,207 +(546,151 +) +1,896,030 +Comprehensive income: +Net income +— +— +— +— +347,069 +— +— +347,069 +Foreign currency translation adjustment, (net of tax of $8,368) +— +— +— +— +— +(14,433 +) +— +(14,433 +) +Total comprehensive income +— +— +— +— +347,069 +(14,433 +) +— +332,636 +Issuance of restricted stock +577 +6 +(6 +) +— +— +— +— +— +Forfeitures of restricted shares +(75 +) +(1 +) +1 +— +— +— +— +— +Exercise of stock options +2,304 +23 +25,525 +— +— +— +— +25,548 +Tax benefit related to stock-based compensation +— +— +16,280 +— +— +— +— +16,280 +Stock-based compensation +— +— +20,131 +— +— +— +— +20,131 +Payment of cash dividend +— +— +— +— +(92,865 +) +— +— +(92,865 +) +Purchase of treasury stock +— +— +— +— +— +— +(70,818 +) +(70,818 +) +Balance, December 31, 2008 +180,192 +$ +1,801 +$ +765,512 +$ +— +$ +1,970,824 +$ +5,774 +$ +(616,969 +) +$ +2,126,942 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Year Ended December 31, +2008 +2007 +2006 +(In thousands) +Cash flows from operating activities: +Net income +$ +347,069 +$ +438,639 +$ +673,254 +Adjustments to reconcile net income to net cash provided by +operating activities: +Goodwill impairment +9,964 +— +— +Depreciation, depletion and other impairment +268,431 +249,206 +196,370 +Provision for bad debts +4,350 +2,550 +5,400 +Dry holes and abandonments +1,617 +1,309 +4,338 +Deferred income tax expense (benefit) +66,039 +38,271 +(3,708 +) +Stock-based compensation expense +20,131 +19,364 +15,179 +Net loss (gain) on asset disposals/retirements +6,071 +(16,545 +) +3,819 +Changes in operating assets and liabilities: +Accounts receivable +(50,567 +) +112,353 +(67,417 +) +Income taxes receivable/payable +(11,258 +) +7,174 +(16,231 +) +Inventory and other current assets +5,492 +4,853 +(47,406 +) +Accounts payable +10,341 +(40,317 +) +27,184 +Accrued expenses +(3,750 +) +(6,104 +) +32,972 +Other liabilities +1,074 +1,471 +13,416 +Net cash provided by operating activities +675,004 +812,224 +837,170 +Cash flows from investing activities: +Acquisitions +— +(29,000 +) +— +Purchases of property and equipment +(448,893 +) +(607,686 +) +(597,919 +) +Proceeds from disposal of assets +11,617 +34,224 +10,934 +Net cash used in investing activities +(437,276 +) +(602,462 +) +(586,985 +) +Cash flows from financing activities: +Purchases of treasury stock +(70,818 +) +(70,850 +) +(450,011 +) +Dividends paid +(92,865 +) +(68,561 +) +(45,825 +) +Tax benefit related to stock-based compensation +16,280 +1,105 +1,087 +Proceeds from borrowings under line of credit +— +142,500 +274,000 +Repayment of borrowings under line of credit +(50,000 +) +(212,500 +) +(154,000 +) +Line of credit issuance costs +— +— +(342 +) +Proceeds from exercise of stock options +25,548 +2,050 +1,946 +Net cash used in financing activities +(171,855 +) +(206,256 +) +(373,145 +) +Effect of foreign exchange rate changes on cash +(2,084 +) +543 +(53 +) +Net increase (decrease) in cash and cash equivalents +63,789 +4,049 +(123,013 +) +Cash and cash equivalents at beginning of year +17,434 +13,385 +136,398 +Cash and cash equivalents at end of year +$ +81,223 +$ +17,434 +$ +13,385 +Supplemental disclosure of cash flow information: +Net cash paid during the year for: +Interest expense +$ +(323 +) +$ +(1,808 +) +$ +(1,278 +) +Income taxes +(126,331 +) +(176,281 +) +(377,847 +) +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., together with its wholly-owned subsidiaries (collectively +referred to herein as “Patterson-UTI” or the +“Company”), is a leading provider of onshore contract +drilling services to major and independent oil and natural gas +operators in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, +Mississippi, Alabama, Colorado, Arizona, Utah, Wyoming, Montana, +North Dakota, South Dakota, Pennsylvania, West Virginia and +western Canada. The Company provides pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. The Company provides drilling fluids, completion fluids +and related services to oil and natural gas operators offshore +in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma +and Louisiana. The Company owns and invests in oil and natural +gas assets as a working interest owner. The oil and natural gas +properties in which the Company holds interests are located +primarily in Texas, New Mexico, Mississippi and Louisiana. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. Except for +wholly-owned subsidiaries, the Company has no controlling +financial interests in any entity which would require +consolidation. +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 its functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting. The Company +follows the percentage-of-completion method of accounting for +footage contract drilling arrangements. Under the +percentage-of-completion method, management estimates are relied +upon in the determination of the total estimated expenses to be +incurred drilling the well. Due to the nature of turnkey +contract drilling arrangements and risks therein, the Company +follows the completed contract method of accounting for such +arrangements. Under this method, all drilling 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. The +Company did not have any footage or turnkey contracts during the +years ended December 31, 2008, 2007 or 2006. +Accounts receivable — Trade accounts receivable +are recorded at the invoiced amount and do not bear interest. +The allowance for doubtful accounts represents the +Company’s estimate of the amount of probable credit losses +existing in the Company’s accounts receivable. The Company +reviews the adequacy of its allowance for doubtful accounts at +least quarterly. Significant individual accounts receivable +balances and balances which have been outstanding greater than +90 days are reviewed individually for collectibility. +Account balances, when determined to be uncollectible, are +charged against the allowance. +F-7 +Table of Contents +Inventories — Inventories consist primarily of +chemical products to be used in conjunction with the +Company’s drilling and completion fluids and pressure +pumping activities. The inventories are stated at the lower of +cost or market, determined by the +first-in, +first-out method. +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change when +equipment becomes idle. The estimated useful lives, in years, +are shown below: +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are +evaluated for impairment when certain triggering events or +changes in circumstances indicate that the carrying values may +not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and the economic operating viability +of the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project after one year following the completion of drilling, the +Company considers the costs of the well to be impaired and +recognizes the costs as expense. Geological and geophysical +costs, including seismic costs, and costs to carry and retain +undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful +exploratory type wells, consisting of lease and well equipment, +lease acquisition costs and intangible development costs, are +depreciated, depleted and amortized on the units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves of each respective field. +The Company reviews its proved oil and natural gas properties +for impairment when a triggering event occurs such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates based on management’s +expectation of future pricing over the lives of the respective +fields. These estimates are then reviewed by an independent +petroleum engineer. If the net book value of a field exceeds its +undiscounted cash flow estimate, impairment expense is measured +and recognized as the difference between its net book value and +discounted cash flow. Unproved oil and natural gas properties +are reviewed quarterly to assess potential 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 — Goodwill is considered to have an +indefinite useful economic life and is not amortized. As such, +the Company assesses impairment of its goodwill annually or on +an interim basis if triggering events or circumstances indicate +that the fair value of the asset has decreased below its +carrying value in accordance with the provisions of Statement of +Financial Accounting Standards No. 142, “Goodwill +and Other Intangible Assets” +(“FAS 142”). As discussed in Note 4, the +Company determined that goodwill in its drilling and completion +fluids reporting unit was impaired in connection with its annual +impairment testing performed as of December 31, 2008. +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Disposals/retirements — Upon disposition or +retirement of property and equipment, the cost and related +accumulated depreciation are removed and any resulting gain or +loss is reflected in the consolidated statement of income. +F-8 +Table of Contents +Net income per common share — The Company +provides a dual presentation of its net income per common share +in its Consolidated Statements of Income: Basic net income per +common share (“Basic EPS”) and diluted net income per +common share (“Diluted EPS”). Basic EPS excludes +dilution and is computed by dividing net income by the weighted +average number of common shares outstanding during the period +excluding non-vested restricted stock. Diluted EPS is based on +the weighted-average number of common shares outstanding plus +the impact of dilutive instruments, including stock options, +restricted stock and restricted stock units using the treasury +stock method. The following table presents information necessary +to calculate net income per share for the years ended +December 31, 2008, 2007 and 2006 as well as potentially +dilutive securities excluded from the weighted average number of +diluted common shares outstanding, as their inclusion would have +been anti-dilutive (in thousands, except per share amounts): +2008 +2007 +2006 +Net income +$ +347,069 +$ +438,639 +$ +673,254 +Weighted average number of common shares outstanding, excluding +non-vested restricted stock +153,379 +154,755 +165,159 +Basic net income per common share +$ +2.26 +$ +2.83 +$ +4.08 +Weighted average number of common shares outstanding, excluding +non-vested restricted stock +153,379 +154,755 +165,159 +Dilutive effect of stock options and restricted shares +1,338 +2,242 +2,254 +Weighted average number of diluted common shares outstanding +154,717 +156,997 +167,413 +Diluted net income per common share +$ +2.24 +$ +2.79 +$ +4.02 +Potentially dilutive securities excluded as anti-dilutive +2,455 +2,460 +800 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. +The Company adopted FASB Interpretation No. 48, +Accounting for Uncertainty in Income Taxes — an +interpretation of FASB Statement No. 109 +(“FIN 48”) on January 1, 2007. +FIN 48 clarifies the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribes a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of FIN 48 in 2007, the Company +reduced a reserve for an uncertain tax position related to a +prior business combination that had originally been recorded as +goodwill (see Note 4). The impact of adjustments to +reserves with respect to other uncertain tax positions was not +material. In connection with the adoption of FIN 48, the +Company established a policy to account for interest and +penalties with respect to income taxes as operating expenses. +Stock based compensation — Prior to +January 1, 2006, the Company accounted for stock based +compensation related to employee stock options and shares of +restricted stock using the recognition and measurement +principles of APB Opinion No. 25, Accounting for Stock +Issued to Employees (“APB 25”), and related +interpretations. Under the provisions of APB 25, expense +associated with stock option grants was measured based on the +intrinsic value of the option at the date of grant and expense +associated with restricted stock grants was measured based on +the fair value of the shares at the date of grant. Reductions in +compensation expense associated with awards that were forfeited +prior to vesting were recognized as those grants were forfeited. +Effective January 1, 2006, the Company adopted the +provisions of Financial Accounting Standards Board Statement +No. 123(R), Share-Based Payment +(“SFAS 123(R)”). SFAS 123(R) requires +the recognition of expense associated with the grant of both +stock +F-9 +Table of Contents +options and restricted stock based on the estimated fair value +of the options or restricted stock at the date of grant, net of +estimated forfeitures. (See Note 10) +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Recently Issued Accounting Standards — In +September 2006, the FASB issued Statement No. 157, Fair +Value Measurements (“FAS 157”). FAS 157 +defines fair value, establishes a framework for measuring fair +value in generally accepted accounting principles, and expands +disclosures about fair value measurement. The initial +application of FAS 157 is limited to financial assets and +liabilities and became effective on January 1, 2008 for the +Company. The impact of the initial application of FAS 157 +was not material. On January 1, 2009, the Company adopted +FAS 157 on a prospective basis for non-financial assets and +liabilities that are not measured at fair value on a recurring +basis. The application of FAS 157 to the Company’s +non-financial assets and liabilities will primarily be limited +to assets acquired and liabilities assumed in a business +combination, asset retirement obligations and asset impairments, +including goodwill and long-lived assets. This application of +FAS 157 is not expected to have a material impact to the +Company. +In December 2007, the FASB issued Statement No. 141(R), +Business Combinations (“FAS 141(R)”) and +Statement No. 160, Noncontrolling Interests in +Consolidated Financial Statements, an amendment of ARB +No. 51 (“FAS 160”). FAS 141(R) is a +revision of Statement No. 141, Business +Combinations , and calls for significant changes from current +practice in accounting for business combinations. +FAS 141(R) is effective for business combinations for which +the acquisition date is on or after the beginning of the first +annual reporting period beginning on or after December 15, +2008. FAS 160 amends ARB 51 to establish accounting and +reporting standards for the non-controlling interest in a +subsidiary and for the deconsolidation of a subsidiary. +FAS 160 is effective for fiscal years beginning on or after +December 15, 2008. Both FAS 141(R) and FAS 160 +became effective for the Company on January 1, 2009. The +application of FAS 141(R) and FAS 160 are not expected +to have a material impact to the Company. +In June 2008, the FASB issued FASB Staff Position +No. EITF 03-6-1, +Determining Whether Instruments Granted in Share-Based +Payment Transactions Are Participating Securities (“FSP +EITF 03-6-1”). +FSP +EITF 03-6-1 +clarifies that share-based payment awards that entitle their +holders to receive non-forfeitable dividends before vesting +should be considered participating securities and, as such, +should be included in the calculation of basic +earnings-per-share +using the two-class method. Certain of the Company’s +share-based payment awards entitle the holders to receive +non-forfeitable dividends and the application of the provisions +of FSP +EITF 03-6-1 +may have the effect of reducing basic and diluted +earnings-per-share +by an immaterial amount. FSP +EITF 03-6-1 +is effective for financial statements issued for fiscal years +beginning after December 15, 2008, as well as interim +periods within those years. Once effective, all prior-period +earnings-per-share +data presented must be adjusted retrospectively to conform with +the provisions of FSP +EITF 03-6-1. +FSP +EITF 03-6-1 +will be effective for the Company beginning in the quarter +ending March 31, 2009 and early application is not +permitted. The adoption of FSP +EITF 03-6-1 +is not expected to have a material impact to the Company. +Reclassifications — Certain reclassifications +have been made to the 2007 and 2006 consolidated financial +statements in order for them to conform with the 2008 +presentation. +2. +Acquisitions +On October 9, 2007, the Company acquired three recently +refurbished SCR electric land-based drilling rigs and spare +drilling equipment for $29.0 million. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +F-10 +Table of Contents +3. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2008 and 2007 (in thousands): +2008 +2007 +Equipment +$ +2,897,431 +$ +2,748,007 +Oil and natural gas properties +89,809 +75,732 +Buildings +61,529 +50,955 +Land +10,196 +9,991 +3,058,965 +2,884,685 +Less accumulated depreciation and depletion +(1,121,853 +) +(1,043,281 +) +Property and equipment, net +$ +1,937,112 +$ +1,841,404 +Depreciation, depletion and other impairment — +The following table summarizes depreciation, depletion and +impairment expense for 2008, 2007 and 2006 (in millions): +2008 +2007 +2006 +Depreciation and impairment expense +$ +256.9 +$ +235.8 +$ +187.3 +Depletion expense +11.5 +13.4 +9.1 +Total +$ +268.4 +$ +249.2 +$ +196.4 +As required under Statement of Financial Accounting Standards +No. 144, Accounting for the Impairment or Disposal of +Long-Lived Assets (“FAS 144”), the Company +evaluates the recoverability of its long-lived assets whenever +events or changes in circumstances indicate that their carrying +amounts may not be recoverable. In light of the adverse market +conditions affecting the Company beginning in the fourth quarter +of 2008 and continuing into 2009, including a substantial +decrease in the operating levels of certain of its business +segments, a significant decline in oil and natural gas commodity +prices, and the preliminary results of the Company’s annual +goodwill impairment test (see Note 4), management deemed it +necessary to assess the recoverability of long-lived assets +within its contract drilling, drilling and completion fluids, +and oil and natural gas business segments. Management concluded +that the Company’s pressure pumping segment was not subject +to the same events and trends noted above to the same degree, +and thus did not require further assessment of recoverability +under FAS 144. +Management performed the first step of its impairment assessment +under the provisions of FAS 144 using the undiscounted cash +flows for each long-lived asset or asset group, using +assumptions and methods consistent with those used in its +assessment of the carrying values of goodwill for its contract +drilling and drilling and completion fluids reporting units. +Based on the results of these impairment tests, the carrying +amounts of long-lived assets in the contract drilling, drilling +and completion fluids and oil and natural gas segments were +determined to be recoverable, except as described below. +Management’s analysis indicated that the carrying amounts +of certain oil and natural gas properties were not recoverable. +The Company recorded a $2.4 million impairment charge in +the fourth quarter of 2008 related to these properties, based on +the related estimated discounted cash flows. This impairment +charge reflects management’s revised estimate of expected +future net cash flows from such properties due, in large part, +to the significant decline in commodity prices in the fourth +quarter of 2008. +Also, during the fourth quarter of 2008, the Company evaluated +its fleet of marketable drilling rigs and identified 22 rigs +that it determined would no longer be marketed as rigs. The +components which made up these rigs were evaluated, and those +components with continuing utility to the Company’s other +marketed rigs (with a net book value of $13.4 million) were +transferred to yards to be used as spare equipment. The +remaining components of these rigs were retired and the +associated net book value of $10.4 million was expensed in +the Company’s statement of operations as a component of +“net loss (gain) on asset disposals/retirements”. +F-11 +Table of Contents +4. +Goodwill +Goodwill by operating segment as of December 31, 2008 and +2007 and changes for the years then ended are as follows (in +thousands): +2008 +2007 +Contract Drilling: +Goodwill at beginning of year +$ +86,234 +$ +89,092 +Changes to goodwill +— +(2,858 +) +Goodwill at end of period +86,234 +86,234 +Drilling and completion fluids: +Goodwill at beginning of year +9,964 +9,964 +Changes to goodwill +(9,964 +) +— +Goodwill at end of period +— +9,964 +Total goodwill +$ +86,234 +$ +96,198 +In connection with the implementation of FIN 48 as of +January 1, 2007 as discussed in Note 1 of these +Consolidated Financial Statements, the Company determined that a +tax reserve of $2.9 million related to a prior business +combination should be reduced to zero. This reserve had +originally been established in connection with the allocation of +the purchase price in the transaction and was reflected as a +component of goodwill recorded in the transaction. +Goodwill is evaluated at least annually to determine if the fair +value of recorded goodwill has decreased below its carrying +value. For purposes of impairment testing, goodwill is evaluated +at the reporting unit level. The Company’s reporting units +for impairment testing have been determined to be its operating +segments. +In connection with its annual goodwill impairment assessment +performed as of December 31, 2008, the Company performed an +impairment test of its contract drilling and drilling and +completion fluids reporting units under the provisions of +FAS 142. In light of the adverse market conditions +affecting the Company’s common stock price beginning in the +fourth quarter of 2008 and continuing into 2009, including a +significant decrease in the number of its rigs operating and a +significant decline in oil and natural gas commodity prices, +management utilized a discounted cash flow methodology to +estimate the fair values of the Company’s reporting units. +In completing its first step of the analysis, management used a +three-year projection of discounted cash flows, plus a terminal +value determined using the constant growth method to estimate +the fair value of its reporting units. In developing these fair +value estimates, certain key assumptions included an assumed +discount rate of 13.99% for all reporting units, an assumed +long-term growth rate of 3.50% for the contract drilling +reporting unit and an assumed long-term growth rate of 2.00% for +the drilling and completion fluids reporting unit. +Based on the results of the first step of the impairment test, +management concluded that no impairment was indicated in its +contract drilling reporting unit; however, an impairment was +indicated in its drilling and completion fluids reporting unit. +In validating this conclusion, management considered the results +of its long-lived asset impairment tests and performed +sensitivity analyses of the key assumptions used in deriving the +respective fair values of its reporting units. Management +performed the second step of the analysis of its drilling and +completion fluids reporting unit, allocating the estimated fair +value to the identifiable tangible and intangible assets and +liabilities of this reporting unit based on their respective +values. This allocation indicated no residual value for +goodwill, and accordingly the Company recorded an impairment +charge of $9.964 million in its December 31, +2008 statement of operations. +In the event that market conditions continue to deteriorate, the +Company may be required to record an impairment of goodwill in +its contract drilling reporting unit in the future, and such +impairment could be material. +F-12 +Table of Contents +5. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2008 and 2007 (in thousands): +2008 +2007 +Salaries, wages, payroll taxes and benefits +$ +30,334 +$ +33,816 +Workers’ compensation liability +70,439 +70,989 +Sales, use and other taxes +12,015 +12,119 +Insurance, other than workers’ compensation +14,209 +16,308 +Other +5,658 +3,602 +$ +132,655 +$ +136,834 +6. +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. This liability is included in the +caption “other liabilities” on the consolidated +balance sheet. The following table describes the changes to the +Company’s asset retirement obligations during 2008 and 2007 +(in thousands): +2008 +2007 +Balance at beginning of year +$ +1,593 +$ +1,829 +Liabilities incurred +516 +276 +Liabilities settled +(424 +) +(862 +) +Accretion expense +59 +61 +Revision in estimated costs of plugging oil and natural gas wells +1,303 +289 +Asset retirement obligation at end of year +$ +3,047 +$ +1,593 +7. +Borrowings +Under Line of Credit +The Company has an unsecured revolving line of credit +(“LOC”) with a maximum borrowing capacity of +$375 million which expires on December 16, 2009. +Interest is paid on outstanding LOC balances at a floating rate +ranging from LIBOR plus 0.625% to 1.0% or the prime rate at the +Company’s election. This arrangement includes various fees, +including a commitment fee on the average daily unused amount +(0.15% at December 31, 2008). There are customary +restrictions and covenants associated with the LOC. Financial +covenants provide for a maximum debt to capitalization ratio and +a minimum interest coverage ratio. The Company does not expect +that the restrictions and covenants will impact its ability to +operate or react to opportunities that might arise. There can be +no assurance that the Company will be able to renew or replace +the existing revolving line of credit with similar terms, if at +all. As of December 31, 2008, the Company had no borrowings +outstanding under the LOC. The Company had $58.5 million in +letters of credit outstanding at December 31, 2008, +however, and as a result the Company had available borrowing +capacity of approximately $316.5 million at such date. +8. +Commitments, +Contingencies and Other Matters +Commitments — As of December 31, 2008, the +Company maintained letters of credit in the aggregate amount of +$58.5 million for the benefit of various insurance +companies as collateral for retrospective premiums and retained +losses which could become payable under the terms of the +underlying insurance contracts. These letters of credit expire +at various times during the calendar year and are typically +renewed annually. As of December 31, 2008, no amounts had +been drawn under the letters of credit. +As of December 31, 2008, the Company had commitments to +purchase approximately $269 million of major equipment. +F-13 +Table of Contents +Contingencies — The Company’s contract +services operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in +personal injury or death, suspended drilling operations, damage +to, or destruction of equipment, damage to producing formations +and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains +general liability insurance coverage of $2.0 million per +occurrence with $10.0 million of aggregate coverage and +excess liability and umbrella coverages up to $200 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. Accrued expenses related to insurance claims are set +forth in Note 5. +The Company believes it is adequately insured for bodily injury +and property damage to others with respect to its operations. +However, such insurance may not be sufficient to protect the +Company against liability for all consequences of well +disasters, extensive fire damage, or damage to the environment. +The Company also carries insurance to cover physical damage to, +or loss of, its rigs. However, it does not cover the full +replacement cost of the rigs and the Company does not carry +insurance against loss of earnings resulting from such damage. +There can be no assurance that such insurance coverage will +always be available on terms that are satisfactory to the +Company. +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic twelve +month renewals unless the Company notifies the Key Employee at +least ninety days before the end of such renewal period that the +term will not be extended. If a change in control of the Company +occurs during the term of the agreement and the Key +Employee’s employment is terminated (i) by the Company +other than for cause or other than automatically as a result of +death, disability or retirement or (ii) by the Key Employee +for good reason (as those terms are defined in the Change in +Control Agreements), then the Key Employee shall generally be +entitled to, among other things, +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +F-14 +Table of Contents +9. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2006, 2007 +and 2008 as follows: +Per Share +Total +(In thousands) +2006: +Paid on March 30, 2006 +$ +0.04 +$ +6,906 +Paid on June 30, 2006 +0.08 +13,413 +Paid on September 29, 2006 +0.08 +13,024 +Paid on December 29, 2006 +0.08 +12,482 +Total cash dividends +$ +0.28 +$ +45,825 +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends +$ +0.44 +$ +68,561 +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +On February 11, 2009, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.05 per share to be paid on March 31, 2009 to holders of +record as of March 12, 2009. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +In 2004, the Company’s Board of Directors authorized a +stock buyback program (“2004 Program”) for the +purchase of the Company’s outstanding common stock in open +market or privately negotiated transactions. During 2006, the +Company completed the purchase of 16,645,342 shares of its +common stock under the 2004 Program in the open market at a cost +of approximately $450 million. +On August 1, 2007, the Company’s Board of Directors +approved a new stock buyback program (“2007 Program”), +authorizing purchases of up to $250 million of the +Company’s common stock in open market or privately +negotiated transactions. During the year ended December 31, +2007, the Company purchased 3,308,850 shares of its common +stock under the 2007 Program at a cost of approximately +$70.4 million. During the year ended December 31, +2008, the Company purchased 3,502,047 shares of its common +stock under the 2007 Program at a cost of approximately +$66.3 million. As of December 31, 2008, the Company is +authorized to purchase approximately $113 million of the +Company’s outstanding common stock under the 2007 Program. +Shares purchased under the stock buyback programs have been +accounted for as treasury stock. +Additionally, the Company purchased 152,235 and +20,269 shares of treasury stock from employees during 2008 +and 2007, respectively. These shares were purchased at fair +market value upon the vesting of restricted stock to provide the +employees with the funds necessary to satisfy payroll tax +withholding obligations. The total purchase price for these +shares was approximately $4.5 million and $496,000 in 2008 +and 2007, respectively. These +F-15 +Table of Contents +purchases were made pursuant to the terms of the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to +the stock buyback programs. +10. +Stock-based +Compensation +Effective January 1, 2006, the Company adopted the +provisions of Financial Accounting Standards Board Statement +No. 123(R), Share-Based Payment +(“SFAS 123(R)”). The Company recognizes the +cost of share-based payments under the fair-value-based method. +The Company uses share-based payments to compensate employees +and non-employee directors. All share-based awards have been +equity instruments in the form of stock options, restricted +stock awards or restricted stock units and have included service +and, in certain cases, performance conditions. The Company +issues shares of common stock when vested stock option awards +are exercised, when restricted stock awards are granted and when +restricted stock units vest. For the year ended +December 31, 2008, the Company recognized +$20.1 million in stock-based compensation expense and a +related income tax benefit of approximately $7.1 million. +For the year ended December 31, 2007, the Company +recognized $19.4 million in stock-based compensation +expense and a related income tax benefit of approximately +$6.7 million. For the year ended December 31, 2006, +the Company recognized $16.3 million in stock-based +compensation expense and a related income tax benefit of +approximately $5.8 million. In addition, effective +January 1, 2006, the Company recognized a benefit in the +form of a cumulative effect of change in accounting principle +associated with the adoption of FAS 123(R) of +$1.1 million, with a related tax expense of $398,000. +During 2005, the Company’s shareholders approved the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the +“2005 Plan”) and the Board of Directors adopted a +resolution that no future grants would be made under any of the +Company’s other previously existing plans. During 2008, the +Company amended the 2005 Plan to, among other things, increase +the total number of shares authorized for grant from 6,250,000 +to 10,250,000. The Company’s share-based compensation plans +at December 31, 2008 follow: +Shares +Shares +Authorized +Awards +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended (“2005 Plan”) +10,250,000 +4,081,571 +4,637,004 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +2,950,634 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +248,938 +— +Amended and Restated Non-Employee Director Stock Option Plan of +Patterson-UTI Energy, Inc. (“Non-Employee Director +Plan”) +— +40,000 +— +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (“1996 Plan”) +— +51,400 +— +Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as +amended (“1993 Plan”) +— +8,100 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over 1 year for non-employee +directors and 3 to 4 years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. +F-16 +Table of Contents +• +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. As of December 31, 2008, only +non-incentive stock options, restricted stock awards and +restricted stock units had been granted under the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Options granted under the Non-Employee Director Plan vest on the +first anniversary of the option grant and have a term of five +years. All options were granted with an exercise price equal to +the fair market value of the related common stock at the time of +grant. +Options granted under the 1996 Plan typically vest over one, +four or five years as dictated by the Compensation Committee. +These options have terms of no more than 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. +Options granted under the 1993 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Stock Options — The Company estimates the grant +date fair values of stock options using the Black-Scholes-Merton +valuation model (“Black-Scholes”). Volatility +assumptions are based on the historic volatility of the +Company’s common stock over the most recent period equal to +the expected term of the options as of the date the options are +granted. The expected term assumptions are based on the +Company’s experience with respect to employee stock option +activity. Dividend yield assumptions are based on the expected +dividends at the time the options are granted. The risk-free +interest rate assumptions are determined by reference to United +States Treasury yields. Weighted-average assumptions used to +estimate grant date fair values for stock options granted in the +years ended December 31, 2008, 2007 and 2006 follow: +2008 +2007 +2006 +Volatility +37.04 +% +36.37 +% +33.18 +% +Expected term (in years) +4.17 +4.00 +4.00 +Dividend yield +2.27 +% +1.97 +% +1.09 +% +Risk-free interest rate +2.91 +% +4.55 +% +4.87 +% +Stock option activity for the year ended December 31, 2008 +follows: +Weighted-Average +Shares +Exercise Price +Outstanding at beginning of year +7,403,084 +$ +17.52 +Granted +834,500 +$ +25.99 +Exercised +(2,303,877 +) +$ +11.09 +Expired +(135 +) +$ +14.64 +Outstanding at end of year +5,933,572 +$ +21.20 +Exercisable at end of year +4,483,793 +$ +19.77 +Options outstanding at December 31, 2008 have an aggregate +intrinsic value of approximately $1.1 million and a +weighted-average remaining contractual term of 6.3 years. +Options exercisable at December 31, 2008 have an aggregate +intrinsic value of approximately $1.1 million and a +weighted-average remaining contractual term of +F-17 +Table of Contents +5.5 years. Additional information with respect to options +granted, vested and exercised during the years ended +December 31, 2008, 2007 and 2006 follows: +2008 +2007 +2006 +Weighted-average grant-date fair value of stock options granted +(per share) +$ +7.20 +$ +7.09 +$ +8.62 +Grant-date fair value of stock options vested during the year +(in thousands) +$ +6,761 +$ +5,613 +$ +6,900 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +45,240 +$ +3,186 +$ +3,377 +As of December 31, 2008, options to purchase +1,449,779 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2008 with respect +to these options that are expected to vest follows: +Aggregate intrinsic value +$ +0 +Weighted-average remaining contractual term +8.85 years +Weighted-average remaining expected term +2.95 years +Weighted-average remaining vesting period +1.89 years +Unrecognized compensation cost +$ +8.9 million +Restricted Stock — For all restricted stock +awards to date, shares of common stock were issued when granted. +Non-vested shares are subject to forfeiture for failure to +fulfill service conditions and, in certain cases, performance +conditions. Non-forfeitable dividends are paid on non-vested +restricted shares. Restricted stock awards prior to +January 1, 2006 were valued at the grant date market value +of the underlying common stock, recognized as contra-equity +deferred compensation and amortized to expense under the +“graded-vesting” method. Implementation of +FAS 123(R) did not change the accounting for the +Company’s non-vested stock awards, except as follows: +• +Prior to January 1, 2006, forfeitures were recognized as +they occurred; +• +From January 1, 2006 forward, forfeitures are estimated in +the determination of periodic compensation cost; +• +Contra-equity deferred compensation was reversed against +paid-in-capital +at January 1, 2006; and +• +Compensation expense is recognized as attributed to each period. +For restricted stock awards granted prior to 2008, the Company +used the “graded-vesting” attribution method to +recognize periodic compensation cost over the vesting period. +For restricted stock awards granted in 2008, the Company uses +the straight-line method to recognize periodic compensation cost +over the vesting period. +Restricted stock activity for the year ended December 31, +2008 follows: +Weighted- +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock outstanding at beginning of year +1,490,150 +$ +26.22 +Granted +576,950 +$ +30.31 +Vested +(562,987 +) +$ +24.37 +Forfeited +(74,542 +) +$ +28.27 +Non-vested restricted stock outstanding at end of year +1,429,571 +$ +28.49 +As of December 31, 2008, approximately +1,368,000 shares of non-vested restricted stock outstanding +are expected to vest. Additional information as of +December 31, 2008 with respect to these shares that are +expected to vest follows: +Aggregate intrinsic value +$ +15.7 million +Weighted-average remaining vesting period +1.66 years +Unrecognized compensation cost +$ +18.3 million +F-18 +Table of Contents +Restricted Stock Units — For all restricted +stock units awarded to date, shares of common stock are not +issued until the awards vest. Awards are subject to forfeiture +for failure to fulfill service conditions. Non-forfeitable cash +dividend equivalents are paid on non-vested restricted stock +units. +Restricted stock unit activity from January 1, 2008 to +December 31, 2008 follows: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock units outstanding at January 1, +2008 +— +$ +— +Granted +17,500 +$ +31.60 +Vested +— +$ +— +Forfeited +— +$ +— +Non-vested restricted stock units outstanding at +December 31, 2008 +17,500 +$ +31.60 +Dividends on Equity Awards — Non-forfeitable +cash dividends and dividend equivalents paid on equity awards +are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of restricted stock awards expected to vest. +• +Dividends are recognized as additional compensation cost for the +portion of restricted stock awards that are not expected to vest +or that ultimately do not vest. +• +Dividend equivalents are recognized as additional compensation +cost for restricted stock units. +Forfeiture assumptions in regard to these cash dividend payments +are the same as forfeiture assumptions used to recognize +compensation cost. +11. +Leases +The Company incurred rent expense of $37.6 million, +$33.9 million and $31.8 million for the years 2008, +2007 and 2006, respectively. Rent expense is primarily related +to short-term equipment rentals that are passed through to +customers. The Company’s obligations under non-cancelable +operating lease agreements are not material to the +Company’s operations or cash flows. +12. +Income +Taxes +The Company adopted FASB Interpretation No. 48, +Accounting for Uncertainty in Income Taxes — an +interpretation of FASB Statement No. 109 +(“FIN 48”), on January 1, 2007. +FIN 48 clarifies the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribes a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of FIN 48, the Company reduced a +reserve that had been established for an uncertain tax position +related to a prior business combination. The reserve was +originally recorded as goodwill (see Note 4). The impact of +adjustments to reserves related to other uncertain tax positions +was not material. As of December 31, 2008, the Company had +no unrecognized tax benefits. In connection with the adoption of +FIN 48, the Company established a policy to account for +interest and penalties related to uncertain income tax positions +as operating expenses. As of December 31, 2008, the tax +years ended December 31, 2005 through December 31, +2007 are open for examination by U.S. taxing authorities. +As of December 31, 2008, the tax years ended +December 31, 2004 through December 31, 2007 are open +for examination by Canadian taxing authorities. +F-19 +Table of Contents +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2008, 2007 and 2006 are as follows (in +thousands): +2008 +2007 +2006 +Federal income tax expense (benefit): +Current +$ +118,887 +$ +172,221 +$ +344,395 +Deferred +58,480 +36,864 +(5,851 +) +177,367 +209,085 +338,544 +State income tax expense: +Current +6,697 +16,456 +21,371 +Deferred +7,116 +983 +1,392 +13,813 +17,439 +22,763 +Foreign income tax expense: +Current +4,256 +5,220 +9,607 +Deferred +443 +424 +353 +4,699 +5,644 +9,960 +Total income tax expense (benefit): +Current +129,840 +193,897 +375,373 +Deferred +66,039 +38,271 +(4,106 +) +Total income tax expense +$ +195,879 +$ +232,168 +$ +371,267 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2008, 2007 and 2006 is summarized as follows: +2008 +2007 +2006 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.7 +1.4 +1.4 +Permanent differences +(0.4 +) +(1.6 +) +(0.8 +) +Other, net +(0.2 +) +(0.2 +) +0.0 +Effective tax rate +36.1 +% +34.6 +% +35.6 +% +F-20 +Table of Contents +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +December 31, +2008 +Change +2007 +Change +2006 +Change +2005 +Deferred tax assets: +Current: +Federal net operating loss carryforwards +$ +— +$ +(374 +) +$ +374 +$ +(1,496 +) +$ +1,870 +$ +— +$ +1,870 +Workers’ compensation allowance +25,984 +(602 +) +26,586 +223 +26,363 +6,902 +19,461 +Embezzlement costs +728 +68 +660 +(13,634 +) +14,294 +14,294 +— +Other +21,623 +3,219 +18,404 +3,903 +14,501 +3,137 +11,364 +48,335 +2,311 +46,024 +(11,004 +) +57,028 +24,333 +32,695 +Non-current: +Federal net operating loss carryforwards +— +— +— +(374 +) +374 +(1,871 +) +2,245 +AMT credit +— +(118 +) +118 +— +118 +— +118 +Federal benefit of foreign deferred tax liabilities +9,416 +443 +8,973 +424 +8,549 +353 +8,196 +Federal benefit of state deferred tax liabilities +7,070 +1,643 +5,427 +735 +4,692 +460 +4,232 +Other +11,994 +1,995 +9,999 +2,890 +7,109 +6,172 +937 +28,480 +3,963 +24,517 +3,675 +20,842 +5,114 +15,728 +Total deferred tax assets +76,815 +6,274 +70,541 +(7,329 +) +77,870 +29,447 +48,423 +Deferred tax liabilities: +Current: +Other +(12,407 +) +(1,753 +) +(10,654 +) +(2,492 +) +(8,161 +) +(1,848 +) +(6,313 +) +Non-current: +Property and equipment basis difference +(302,327 +) +(70,362 +) +(231,965 +) +(28,466 +) +(203,500 +) +(23,775 +) +(179,725 +) +Other +(3,870 +) +8,172 +(12,042 +) +(6,741 +) +(5,301 +) +(110 +) +(5,191 +) +(306,197 +) +(62,190 +) +(244,007 +) +(35,207 +) +(208,801 +) +(23,885 +) +(184,916 +) +Total deferred tax liabilities +(318,604 +) +(63,943 +) +(254,661 +) +(37,699 +) +(216,962 +) +(25,733 +) +(191,229 +) +Net deferred tax liability +$ +(241,789 +) +$ +(57,669 +) +$ +(184,120 +) +$ +(45,028 +) +$ +(139,092 +) +$ +3,714 +$ +(142,806 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2008 and +2007 to be realized as a result of the reversal of existing +taxable temporary differences giving rise to deferred tax +liabilities and the generation of taxable income; therefore, no +valuation allowance is necessary. +Other deferred tax assets consist primarily of various allowance +accounts and tax-deferred expenses expected to generate future +tax benefit of approximately $34 million. Other deferred +tax liabilities consist primarily of receivables from insurance +companies and tax-deferred income not yet recognized for tax +purposes. +F-21 +Table of Contents +13. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $4.8 million in 2008, $4.2 million in +2007 and $3.1 million in 2006 for the Company’s cash +contributions to the plan. +14. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to four business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services, (iii) drilling and +completion fluids services and (iv) the investment, on a +working interest basis, in oil and natural gas properties. Each +of these segments represents a distinct type of business based +upon the type and nature of services and products offered. These +segments have separate management teams which report to the +Company’s chief operating decision maker and their results +are regularly reviewed by the chief operation decision maker for +purposes of making decisions about resource allocation and +assessing their performance. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2008, the Company +had 344 marketable land-based drilling rigs, of which 93 of the +drilling rigs were based in west Texas and southeastern New +Mexico; 92 in north central and eastern Texas, northern +Louisiana, Mississippi and Alabama; 56 in the Rocky Mountain +region (Colorado, Arizona, Utah, Wyoming, Montana, North Dakota +and South Dakota); 50 in south Texas; 27 in the Texas panhandle, +Oklahoma and Arkansas; 20 in western Canada; and 6 in the +Appalachian Basin. +Pressure Pumping — The Company provides +pressure pumping services primarily in the Appalachian Basin. +Pressure pumping services consist primarily of well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Well stimulation involves processes inside a +well designed to enhance the flow of oil, natural gas, or other +desired substances from the well. Cementing is the process of +inserting material between the hole and the pipe to center and +stabilize the pipe in the hole. +Drilling and Completion Fluids — The Company +provides drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, New Mexico, Oklahoma and the Gulf Coast +region of Louisiana. Drilling and completion fluids are used by +oil and natural gas operators during the drilling process to +control pressure when drilling oil and natural gas wells. +Oil and Natural Gas — The Company has been +engaged in the development, exploration, acquisition and +production of oil and natural gas. Through October 31, +2007, the Company served as operator with respect to several +properties and was actively involved in the development, +exploration, acquisition and production of oil and natural gas. +Effective November 1, 2007 the Company sold the related +operations portion of its exploration and production business. +The Company continues to own and invest in oil and natural gas +assets as a working interest owner. The Company’s oil and +natural gas interests are located primarily in Texas, New +Mexico, Mississippi and Louisiana. +F-22 +Table of Contents +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Revenues: +Contract drilling(a) +$ +1,808,600 +$ +1,744,884 +$ +2,174,805 +Pressure pumping +217,494 +202,812 +145,671 +Drilling and completion fluids(b) +145,423 +128,447 +192,974 +Oil and natural gas +42,360 +41,637 +39,187 +Total segment revenues +2,213,877 +2,117,780 +2,552,637 +Elimination of intercompany revenues(a)(b) +(4,751 +) +(3,586 +) +(6,051 +) +Total revenues +$ +2,209,126 +$ +2,114,194 +$ +2,546,586 +Income (loss) before income taxes: +Contract drilling +$ +531,025 +$ +558,792 +$ +991,449 +Pressure pumping +42,019 +64,257 +44,835 +Drilling and completion fluids +(4,558 +) +6,528 +28,759 +Oil and natural gas +13,711 +10,998 +8,660 +582,197 +640,575 +1,073,703 +Corporate and other +(34,596 +) +(30,799 +) +(27,639 +) +Embezzlement (costs) recoveries(c) +— +43,955 +(3,081 +) +Net (loss) gain on asset disposals/retirements(d) +(6,071 +) +16,545 +(3,819 +) +Interest income +1,555 +2,355 +5,925 +Interest expense +(639 +) +(2,187 +) +(1,602 +) +Other +502 +363 +347 +Income before income taxes +$ +542,948 +$ +670,807 +$ +1,043,834 +Identifiable assets: +Contract drilling +$ +2,255,421 +$ +2,132,910 +$ +1,849,923 +Pressure pumping +210,805 +154,120 +111,787 +Drilling and completion fluids +99,433 +91,989 +106,032 +Oil and natural gas +31,760 +37,885 +65,443 +Corporate and other(e) +115,398 +48,295 +59,318 +Total assets +$ +2,712,817 +$ +2,465,199 +$ +2,192,503 +Depreciation, depletion and impairment: +Contract drilling +$ +229,311 +$ +213,812 +$ +168,607 +Pressure pumping +19,600 +14,311 +9,896 +Drilling and completion fluids +2,830 +2,860 +2,706 +Oil and natural gas +15,856 +17,410 +14,368 +Corporate and other +834 +813 +793 +Total depreciation, depletion and impairment +$ +268,431 +$ +249,206 +$ +196,370 +Capital expenditures: +Contract drilling +$ +360,645 +$ +539,506 +$ +531,087 +Pressure pumping +61,289 +47,582 +41,262 +Drilling and completion fluids +3,467 +3,082 +4,222 +Oil and natural gas +22,981 +17,516 +21,198 +Corporate and other +511 +— +150 +Total capital expenditures +$ +448,893 +$ +607,686 +$ +597,919 +(a) +Includes contract drilling intercompany revenues of +approximately $4.6 million, $3.2 million and +$5.4 million for the years ended December 31, 2008, +2007 and 2006, respectively. +F-23 +Table of Contents +(b) +Includes drilling and completion fluids intercompany revenues of +approximately $177,000, $348,000 and $616,000 for the years +ended December 31, 2008, 2007 and 2006, respectively. +(c) +The Company’s former CFO has pleaded guilty to criminal +charges and has been sentenced and is serving a term of +imprisonment arising out of his embezzlement of funds from the +Company prior to his termination in 2005. Embezzlement costs in +2006 include professional fees and other costs incurred as a +result of the embezzlement. The net embezzlement recovery in +2007 includes the recognition of the recovery of assets seized +by a court appointed receiver, net of related professional fees. +(d) +Gains or losses associated with the disposal or retirement of +assets relate to decisions of the executive management group +regarding corporate strategy. Accordingly, the related gains or +losses have been separately presented and excluded from the +results of specific segments. +(e) +Corporate and other assets primarily include cash on hand +managed by the parent corporation and certain deferred Federal +income tax assets. +15. +Concentrations +of Credit Risk +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial +institutions. At December 31, 2008 and 2007, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2008 +2007 +Deposits in FDIC and SIPC-insured institutions under insurance +limits +$ +588 +$ +462 +Deposits in FDIC and SIPC-insured institutions over insurance +limits +79,387 +53,112 +Deposits in Foreign Banks +18,805 +6,282 +98,780 +59,856 +Less outstanding checks and other reconciling items +(17,557 +) +(42,422 +) +Cash and cash equivalents +$ +81,223 +$ +17,434 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2008, 2007, or 2006. The Company recognized +bad debt expense for 2008, 2007 and 2006 of $4.4 million, +$2.6 million and $5.4 million, respectively. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +16. +Related +Party Transactions +Joint Operation of Oil and Natural Gas +Properties — Through October 31, 2007, the +Company served as operator with respect to several properties +and was actively involved in the development, exploration, +acquisition and production of oil and natural gas. Effective +November 1, 2007, the Company sold the operations portion +of its exploration and production business. The Company +continues to own and invest in oil and natural gas assets as a +working interest owner. During the time that the Company served +as operator, it served as operator with respect to certain oil +and natural gas properties in which certain of its affiliated +persons have participated, either individually or through +entities they control. These participations were typically +through working interests in prospects or properties originated +or acquired by Patterson Petroleum, LLC, a wholly owned +subsidiary of Patterson-UTI. +During the time that the Company served as operator, sales of +working interests to affiliated parties were made by the Company +at its cost, comprised of Patterson-UTI’s costs of +acquiring and preparing the working interests for sale plus a +promote fee in some cases. These costs were paid by the working +interest owners on a pro rata basis based +F-24 +Table of Contents +upon their working interest ownership percentage. The price at +which working interests were sold to affiliated persons was the +same price at which working interests were sold to unaffiliated +persons except that in some cases the affiliated persons also +paid a promote fee. The affiliated persons received oil and +natural gas production revenue (net of royalty) of +$19.0 million and $15.8 million from these properties +in 2007 and 2006, respectively. These persons or entities in +turn paid for joint operating costs (including drilling and +other development expenses) of $9.2 million and +$14.1 million incurred in 2007 and 2006, respectively. +17. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2007 +Operating revenues +$ +547,101 +$ +522,558 +$ +524,002 +$ +520,533 +Operating income +179,725 +215,136 +144,100 +131,315 +Net income +115,801 +139,551 +98,181 +85,106 +Net income per common share: +Basic +$ +0.75 +$ +0.90 +$ +0.63 +$ +0.56 +Diluted +$ +0.73 +$ +0.88 +$ +0.62 +$ +0.55 +2008 +Operating revenues +$ +504,554 +$ +526,283 +$ +608,532 +$ +569,757 +Operating income +119,874 +126,419 +165,282 +129,955 +Net income +77,409 +81,422 +108,746 +79,492 +Net income per common share: +Basic +$ +0.51 +$ +0.53 +$ +0.70 +$ +0.52 +Diluted +$ +0.50 +$ +0.52 +$ +0.70 +$ +0.52 +F-25 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND QUALIFYING +ACCOUNTS +Charged to +Costs and +Description +Beginning Balance +Expenses +Deductions(1) +Ending Balance +(In thousands) +Year Ended December 31, 2008 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,014 +$ +4,350 +$ +5,034 +$ +9,330 +Year Ended December 31, 2007 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +7,484 +$ +2,550 +$ +20 +$ +10,014 +Year Ended December 31, 2006 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +2,199 +$ +5,400 +$ +115 +$ +7,484 +(1) +Uncollectible accounts written off net of recoveries. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 18, 2009 +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 +February 18, 2009. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +Table of Contents +EXHIBIT INDEX +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as +amended (filed March 13, 1998 as Exhibit 10.1 to the +Company’s Registration Statement on +Form S-8 +(File +No. 333-47917) +and incorporated herein by reference).* +10 +.3 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.4 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.5 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.6 +Amended and Restated Patterson-UTI Energy, Inc. Non-Employee +Director Stock Option Plan(filed July 28, 2003 as +Exhibit 4.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.7 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.8 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.9 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.10 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 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 (filed +August 9, 2004 as Exhibit 10.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.12 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed +August 9, 2004 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +Table of Contents +10 +.13 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed +August 9, 2004 as Exhibit 10.4 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.14 +Restricted Stock Award Agreement dated April 28, 2004 +between Patterson-UTI Energy, Inc. and John E. Vollmer III +(filed August 9, 2004 as Exhibit 10.6 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.15 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.16 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.19 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.20 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +William L. Moll, Jr. and Gregory W. Pipkin (filed April 28, +2004 as Exhibit 10.11 to the Company’s Annual Report +on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.21 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.23 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and William L. Moll, Jr. (filed +November 5, 2007 as Exhibit 10.7 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.27 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +Table of Contents +10 +.28 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and William L. Moll, Jr., entered +into November 1, 2007 (filed November 5, 2007 as +Exhibit 10.12 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.29 +Credit Agreement dated as of December 17, 2004 among +Patterson-UTI Energy, Inc., as the Borrower, Bank of America, +N.A., as administrative agent, L/C Issuer and a Lender and the +other lenders and agents party thereto (filed on +December 23, 2004 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.30 +Commitment Increase and Joinder Agreement, dated as of +August 2, 2006, by and among Patterson-UTI Energy, Inc., +the guarantors party thereto, the lenders party thereto, and +Bank of America, N.A. as Administrative Agent, L/C Issuer and +Lender (filed August 21, 2006 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.31 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +14 +.1 +Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics +for Senior Financial Executives (filed 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). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of +Form 10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/filing_metadata.csv b/raw/filings/0000889900/2008/0000950134-09-003225/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..5d8303b99897afeac03deba7e0161d7eacb63fbd --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2009-02-19,2008-12-31,2009-02-18T23:16:10.000Z,0000950134-09-003225,d66380e10vk.htm,FORM 10-K,1180455,0,0,https://www.sec.gov/Archives/edgar/data/889900/000095013409003225/d66380e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095013409003225/,2008,2008,1 diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/item1.txt b/raw/filings/0000889900/2008/0000950134-09-003225/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..b9b3ece96808a88b1894ec30d9444a6ec7081d15 --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/item1.txt @@ -0,0 +1,640 @@ +Item 1. +Business +Available +Information +This Annual Report on +Form 10-K, +along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of +1934, are available free of charge through our Internet website +(www.patenergy.com) as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the +SEC. The information contained on our website is not part of +this Report or other filings that we make with the SEC. You may +read and copy any materials we file with the SEC at the +SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the +operation of the Public Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site (www.sec.gov) that contains +reports, proxy and information statements and other information +regarding issuers that file electronically with the SEC. +Overview +Based on publicly available information, we believe we are the +second largest operator of land-based drilling rigs in the +United States. The Company was formed in 1978 and reincorporated +in 1993 as a Delaware corporation. +1 +Table of Contents +Our contract drilling business operates primarily in Texas, New +Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, +Colorado, Arizona, Utah, Wyoming, Montana, North Dakota, South +Dakota, Pennsylvania, West Virginia and western Canada. +As of December 31, 2008, we had a drilling fleet that +consisted of 344 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drilling rig components and equipment. +We provide pressure pumping services to oil and natural gas +operators primarily in the Appalachian Basin. These services +consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. We +provide drilling fluids, completion fluids and related services +to oil and natural gas operators offshore in the Gulf of Mexico +and on land in Texas, New Mexico, Oklahoma and Louisiana. +Drilling and completion fluids are used by oil and natural gas +operators to control pressure when drilling and completing oil +and natural gas wells. We own and invest in oil and natural gas +assets as a working interest owner. Our oil and natural gas +interests are located primarily in Texas, New Mexico, +Mississippi and Louisiana. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to four industry segments: +• +contract drilling, +• +pressure pumping services, +• +drilling and completion fluids services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2008, 2007 +and 2006, except that in 2008 our drilling and completion fluids +services segment reported an operating loss due to a non-cash +charge recognized for the impairment of goodwill in that segment. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 14 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2008, we had 344 marketable land-based +drilling rigs which were based in the following regions: +• +93 in west Texas and southeastern New Mexico, +• +92 in north central and eastern Texas, northern Louisiana, +Mississippi and Alabama, +• +56 in the Rocky Mountain region (Colorado, Arizona, Utah, +Wyoming, Montana, North Dakota and South Dakota), +• +50 in south Texas and southern Louisiana, +• +27 in the Texas panhandle, Oklahoma and Arkansas, +• +6 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Eighty seven of these drilling rigs are electric rigs and 257 +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 +2 +Table of Contents +electricity to power the rig. We also have a substantial +inventory of drilling rig components and equipment which may be +used in the activation of additional drilling rigs or as +replacement parts for marketable rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.4 billion during the last three years on capital +expenditures to (1) build new land drilling rigs and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2008, 2007 and 2006, we spent approximately +$361 million, $540 million and $531 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the size of drilling rig +used for a particular job. Our rigs are capable of vertical or +horizontal drilling. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well basis or a term basis. Well-to-well contracts are +generally short-term in nature and cover the drilling of a +single well or a series of wells. Term contracts are entered +into for a specified period of time (frequently one to three +years) and provide for the use of the drilling rig to drill +multiple wells. During 2008, our average number of days to drill +a well (which includes moving to the drill site, rigging up and +rigging down) was approximately 22 days. +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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. We generally +indemnify our customers against claims by our employees and +claims that might arise from surface pollution caused by spills +of fuel, lubricants and other solvents within our control. The +customers generally indemnify us against claims that might arise +from other surface and subsurface pollution, except claims that +might arise from our gross negligence. Each drilling contract +will contain the actual terms setting forth our rights and +obligations and those of the particular customer. +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. All of our contracts during the years +ended December 31, 2008, 2007 and 2006 provided for payment +on a daywork basis. Our bid for each contract depends upon +location, depth and anticipated complexity of the well, +on-site +drilling conditions, equipment to be used, estimated risks +involved, estimated duration of the job, availability of +drilling rigs and other factors particular to each proposed well. +Daywork +Contracts +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving, or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. All of our drilling contracts in 2006, 2007 and +2008 were daywork contracts. +Footage +Contracts +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling +3 +Table of Contents +contractor than daywork contracts. Under footage contracts, the +drilling contractor typically assumes certain risks associated +with loss of the well from fire, blowouts and other risks. We +did not enter into any footage contracts in the past three years. +Turnkey +Contracts +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed scope of +the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. We did not enter into any turnkey contracts +in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2008 +2007 +2006 +Average rigs operating(1) +254 +244 +296 +Number of rigs operated +315 +338 +331 +Number of wells drilled +4,218 +4,237 +5,050 +Number of operating days +93,068 +89,095 +108,221 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2008 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +65 +9 +74 +12,000 to 15,999 +197 +8 +205 +16,000 to 30,000 +62 +— +62 +Totals +324 +20 +344 +At December 31, 2008, we owned and operated 308 trucks and +405 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and enhances +the efficiency of our contract drilling operations, particularly +in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, New Mexico, +Oklahoma, Wyoming, Utah and western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion +4 +Table of Contents +of new wells and remedial work on existing wells. Most wells +drilled in the Appalachian Basin require some form of fracturing +or other stimulation to enhance the flow of oil and natural gas +by pumping fluids under pressure into the well bore. Generally, +Appalachian Basin wells require cementing services before +production commences. The cementing process inserts material +between the wall of the well bore and the casing to center and +stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2008 includes: +• +42 cement pumper trucks, +• +66 triplex pumper trucks, +• +54 nitrogen pumper trucks, +• +5 quintiplex pump trailers, +• +31 blender trucks, +• +28 bulk acid trucks/acid pumper trucks, +• +47 bulk cement trucks, +• +27 bulk nitrogen trucks, +• +6 bulk nitrogen tractor trailer combinations, +• +69 bulk sand trucks, +• +14 sand pneumatic trucks, +• +7 sand pneumatic trailers, +• +9 flatbed material trucks, +• +24 connection trucks, +• +2 shale fracturing manifold trailers, +• +1 shale fracturing iron trailer, +• +8 shale fracturing sand field bins with conveyors, +• +2 shale fracturing large conveyors, and +• +21 tractors. +Drilling +and Completion Fluids Operations +General — We provide drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We serve our offshore +customers through six stockpoint facilities located along the +Gulf of Mexico in Texas and Louisiana and our land-based +customers through fourteen stockpoint facilities in Texas, +Louisiana, Oklahoma and New Mexico. +Drilling Fluids — Drilling fluid products and +systems are used to cool and lubricate the bit during drilling +operations, contain formation pressures (thereby minimizing +blowout risk), suspend and remove rock cuttings from the hole +and maintain the stability of the wellbore. Technical services +are provided to promote effective application of the products +and systems used to optimize drilling operations. +Completion Fluids — After a well is drilled, +the well casing is set and cemented into place. At that point, +the drilling fluid services are complete and the drilling fluids +are circulated out of the well and replaced with completion +fluids. Completion fluids, also known as clear brine fluids, are +solids-free, clear salt solutions that have high specific +gravities. Combined with a range of specialty chemicals, these +fluids are used to control bottom-hole pressures and to meet +specific corrosion, inhibition, viscosity and fluid loss +requirements. +5 +Table of Contents +Raw Materials — The profitability of our +drilling and completion fluids operations is affected by the +availability and pricing 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 we have with producers of these raw +materials. +Barite Grinding Facility — We operate a barite +grinding facility with two barite grinding mills in Houma, +Louisiana. This facility allows us to grind raw barite into the +powder additive used in drilling fluids. +Other Equipment — We own and operate 13 trucks +and 141 trailers and lease another 34 trucks which are used to +transport drilling and completion fluids and related equipment. +Oil and +Natural Gas Operations +General — We have been engaged in the +development, exploration, acquisition and production of oil and +natural gas. Through October 31, 2007, we served as +operator with respect to several properties and were actively +involved in the development, exploration, acquisition and +production of oil and natural gas. Effective November 1, +2007, we sold the related operations portion of our exploration +and production business, which was the portion of that business +that actively managed the development, exploration, acquisition +and production of oil and natural gas. We continue to own and +invest in oil and natural gas assets as a working interest +owner. Our oil and natural gas interests are located primarily +in producing regions of Texas, New Mexico, Mississippi and +Louisiana. +Customers +The customers of each of our three oil service business segments +are oil and natural gas operators. Our customer base includes +both major and independent oil and natural gas operators. During +2008, no single customer accounted for 10% or more of our +consolidated operating revenues. +Competition +Contract Drilling and Pressure Pumping +Businesses — Our land drilling and pressure +pumping businesses are highly competitive. At times, available +land drilling rigs and pressure pumping equipment exceed the +demand for such equipment. The equipment can also be moved from +one market to another in response to market conditions. +Drilling and Completion Fluids Business — The +drilling and completion fluids industry is highly competitive +and price is generally the most important factor. Other +competitive factors include the availability of chemicals and +experienced personnel, the reputation of the fluids services +provider in the drilling industry and relationships with +customers. Some of our competitors have substantially more +resources and longer operating histories than we have. +Government +and Environmental Regulation +All of our operations and facilities are subject to numerous +Federal, state, foreign, and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations have not +required the expenditure of significant resources. We do not +anticipate any material capital expenditures for environmental +control facilities or extraordinary expenditures to comply with +environmental rules and regulations in the foreseeable future. +However, +6 +Table of Contents +compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. State and Federal +environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 operated by us or our +predecessors. In addition, some of these properties have been +operated by third parties over whom we have no control of their +treatment of hydrocarbon and other materials or the manner in +which they may have disposed of or released such materials. +The Federal Comprehensive Environmental Response Compensation +and Liability Act of 1980, as amended, commonly known as CERCLA, +and comparable state statutes impose strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act is more comprehensive and stringent than +previous oil pollution liability and prevention laws. It imposes +strict liability for a comprehensive and expansive list of +damages from an oil spill into waters from facilities. Liability +may be imposed for oil removal costs and a variety of public and +private damages. Penalties may also be imposed for violation of +Federal safety, construction and operating regulations, and for +failure to report a spill or to cooperate fully in a +clean-up. +The Oil Pollution Act also expands the authority and capability +of the Federal government to direct and manage oil spill +clean-up and +operations, and requires operators to prepare oil spill response +plans in cases where it can reasonably be expected that +substantial harm will be done to the environment by discharges +on or into navigable waters. We have spill prevention control +and countermeasure plans in place for our oil and natural gas +properties in each of the areas in which we operate and for each +of the stockpoints operated by our drilling and completion +fluids business. Failure to comply with ongoing requirements or +inadequate cooperation during a spill event may subject a +responsible party, such as us, to civil or criminal actions. +Although the liability for owners and operators is the same +under the Federal Water Pollution Act, the damages recoverable +under the Oil Pollution Act are potentially much greater and can +include natural resource damages. +Our operations are also subject to Federal, state and local +regulations for the control of air emissions. The Federal Clean +Air Act, as amended, and various state and local laws impose +certain air quality requirements on us. Amendments to the Clean +Air Act revised the definition of “major source” such +that emissions from both wellhead and associated equipment +involved in oil and natural gas production may be added to +determine if a source is a +7 +Table of Contents +“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, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +all-risk physical damages, +• +employer’s liability, +• +commercial general liability, and +• +workers compensation insurance. +We believe that we are adequately insured for bodily injury and +property damage to others with respect to our operations. Such +insurance, however, may not be sufficient to protect us against +liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. Such insurance does not, however, cover the +full replacement cost of the rigs, and we do not carry insurance +against loss of earnings resulting +8 +Table of Contents +from such damage. In view of the difficulties that may be +encountered in renewing such insurance at reasonable rates, no +assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +Employees +We had approximately 6,600 full-time employees at +December 31, 2008. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada, and our +pressure pumping division in the Appalachian Basin to a lesser +extent, are subject to slow periods of activity during the +Spring thaw. +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. \ No newline at end of file diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/item13.txt b/raw/filings/0000889900/2008/0000950134-09-003225/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..97cbc88da95dc5aeea63960da2883c0ca43e0a25 --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/item13.txt @@ -0,0 +1,6 @@ +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/item9a.txt b/raw/filings/0000889900/2008/0000950134-09-003225/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..0e412a4df20fc18eddeb12e0572abec312179f90 --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/item9a.txt @@ -0,0 +1,56 @@ +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined 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. +Based on this evaluation, our CEO and CFO concluded that, as of +December 31, 2008, our disclosure controls and procedures +were effective to ensure that information required to be +disclosed by us in reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported +within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO +and CFO, as appropriate to allow timely decisions regarding +required disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2008, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2008. +The effectiveness of our internal control over financial +reporting as of December 31, 2008 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and is incorporated by reference into Item 8 +of this Annual Report on +Form 10-K. +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. \ No newline at end of file diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/rp_note.txt b/raw/filings/0000889900/2008/0000950134-09-003225/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2008/0000950134-09-003225/rpt_disclosure.txt b/raw/filings/0000889900/2008/0000950134-09-003225/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..df3c93ffc7d871a8f4432bb45f474988f7d07797 --- /dev/null +++ b/raw/filings/0000889900/2008/0000950134-09-003225/rpt_disclosure.txt @@ -0,0 +1,24 @@ +related person transaction are considered, including whether +such transaction is in, or not inconsistent with, the best +interest of Patterson-UTI and whether, in appropriate cases, +such transaction is on commercial terms at least as favorable to +Patterson-UTI as would otherwise be available to or from an +unrelated third party or to Patterson-UTI’s employees +generally. Related person transactions generally include +transactions in an amount that exceeds $50,000 between +Patterson-UTI or any of its subsidiaries and an executive +officer, a director (or nominee to become director), an +immediate family member of any of the foregoing or any entity in +which any of the foregoing has a 10% or greater beneficial +ownership interest or in which they are an executive officer, +general partner, principal or engaged in a similar position. +Certain related person transactions have been pre-approved under +the terms of the policy, including, subject to certain +exceptions and limitations, the sale to or purchase from +Patterson-UTI of goods and services by entities related to +directors in the ordinary course of business that are immaterial +to Patterson-UTI and with respect to which the director has no +direct economic interest or decision making authority. +20 +Table of Contents +SECURITY \ No newline at end of file diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/filing.txt b/raw/filings/0000889900/2009/0000950123-10-014515/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..aa6c7e7f54457507baaea6d1f6d6ded863cc4d4e --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/filing.txt @@ -0,0 +1,8023 @@ +10-K +1 +d70467e10vk.htm +FORM 10-K +e10vk +Table of Contents +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. +20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2009 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, +Inc. +(Exact name of registrant as +specified in its charter) +Delaware +(State or other jurisdiction +of +incorporation or organization) +75-2504748 +(I.R.S. Employer +Identification No.) +450 Gears Road, Suite 500, Houston, Texas +(Address of principal +executive offices) +77067 +(Zip +Code) +Registrant’s telephone number, including area code: +(281) 765-7100 +Securities Registered Pursuant to Section 12(b) of the +Act: +Title of Each Class +Name of Exchange on Which Registered +Common Stock, $0.01 Par Value +The Nasdaq Global Select Market +Preferred Share Purchase Rights +The Nasdaq Global Select Market +Securities +Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known +seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes þ or +No +o +Indicate by check mark if the registrant is not required to file +reports pursuant to Section 13 or Section 15(d) of the +Act. Yes o or +No +þ +Indicate by check mark whether the registrant (1) has filed +all reports required to be filed by Section 13 or 15(d) of +the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant +was required to file such reports), and (2) has been +subject to such filing requirements for the past +90 days. Yes þ No o +Indicate by check mark whether the registrant has submitted +electronically and posted on its corporate Website, if any, +every Interactive Data File required to be submitted and posted +pursuant to Rule 405 of +Regulation S-T +during the preceding 12 months (or for such shorter period +that the registrant was required to submit and post such +files). Yes þ or +No +o +Indicate by check mark if disclosure of delinquent filers +pursuant to Item 405 of +Regulation S-K +is not contained herein, and will not be contained, to the best +of registrant’s knowledge, in definitive proxy or +information statements incorporated by reference in +Part III of this +Form 10-K +or any amendment to this +Form 10-K. þ +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, a non-accelerated filer +or a smaller reporting company. See definition of “large +accelerated filer,” “accelerated filer” and +“smaller reporting company” in +Rule 12b-2 +of the Exchange Act. +Large +accelerated +filer þ +Accelerated +filer o +Non-accelerated +filer o +Smaller +reporting +company o +Indicate by check mark whether the registrant is a shell company +(as defined in +Rule 12b-2 +of the +Act). Yes o No þ +The aggregate market value of the voting and non-voting common +equity held by non-affiliates of the registrant as of +June 30, 2009, the last business day of the +registrant’s most recently completed second fiscal quarter, +was $1,944,259,033, calculated by reference to the closing price +of $12.86 for the common stock on the Nasdaq Global Select +Market on that date. +As of February 17, 2010, the registrant had outstanding +153,567,174 shares of common stock, $.01 par value, +its only class of common stock. +Documents incorporated by reference: +Portions of the registrant’s definitive proxy statement for +the 2010 Annual Meeting of Stockholders are incorporated by +reference into Part III of this report. +Table of Contents +DISCLOSURE +REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on +Form 10-K +(this “Report”) and other public filings and press +releases by us contain “forward-looking statements” +within the meaning of the Securities Act of 1933, as amended +(the “Securities Act”), the Securities Exchange Act of +1934, as amended (the “Exchange Act”), and the Private +Securities Litigation Reform Act of 1995, as amended. These +“forward-looking statements” involve risk and +uncertainty. These forward-looking statements include, without +limitation, statements relating to: liquidity; financing of +operations; continued volatility of oil and natural gas prices; +source and sufficiency of funds required for immediate capital +needs and additional rig acquisitions (if further opportunities +arise); impact of inflation; demand for our services; and other +matters. Our forward-looking statements can be identified by the +fact that they do not relate strictly to historic or current +facts and often use words such as “believes,” +“budgeted,” “continue,” “expects,” +“estimates,” “project,” “will,” +“could,” “may,” “plans,” +“intends,” “strategy,” or +“anticipates,” or the negative thereof or other words +and expressions of similar meaning. The forward-looking +statements are based on certain assumptions and analyses we make +in light of our experience and our perception of historical +trends, current conditions, expected future developments and +other factors we believe are appropriate in the circumstances. +Although we believe that the expectations reflected in such +forward-looking statements are reasonable, we can give no +assurance that such expectations will prove to have been +correct. Forward-looking statements may be made orally or in +writing, including, but not limited to, Management’s +Discussion and Analysis of Financial Condition and Results of +Operations included in this Report and other sections of our +filings with the United States Securities and Exchange +Commission (the “SEC”) under the Exchange Act and the +Securities Act. +Forward-looking statements are not guarantees of future +performance and a variety of factors could cause actual results +to differ materially from the anticipated or expected results +expressed in or suggested by these forward-looking statements. +Factors that might cause or contribute to such differences +include, but are not limited to, deterioration of global +economic conditions, declines in oil and natural gas prices that +could adversely affect demand for our services and their +associated effect on day rates, rig utilization and planned +capital expenditures, excess availability of land drilling rigs, +including as a result of the reactivation or construction of new +land drilling rigs, adverse industry conditions, adverse credit +and equity market conditions, difficulty in integrating +acquisitions, demand for oil and natural gas, shortages of rig +equipment, governmental regulation and ability to retain +management and field personnel. Refer to “Risk +Factors” contained in Part 1 of this Report for a more +complete discussion of these and other factors that might affect +our performance and financial results. You are cautioned not to +place undue reliance on any of our forward-looking statements. +These forward-looking statements are intended to relay our +expectations about the future, and speak only as of the date +they are made. We undertake no obligation to publicly update or +revise any forward-looking statement, whether as a result of new +information, changes in internal estimates or otherwise. +PART I +Item 1. +Business +Available +Information +This Report, along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Exchange Act, are available +free of charge through our Internet website (www.patenergy.com) +as soon as reasonably practicable after we electronically file +such material with, or furnish it to, the SEC. The information +contained on our website is not part of this Report or other +filings that we make with the SEC. You may read and copy any +materials we file with the SEC at the SEC’s Public +Reference Room at 100 F Street, NE, Washington, DC +20549. You may obtain information on the operation of the Public +Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site (www.sec.gov) that contains +reports, proxy and information statements and other information +regarding issuers that file electronically with the SEC. +1 +Table of Contents +Overview +We own and operate one of the largest fleets of land-based +drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, +Utah, Wyoming, Montana, North Dakota, Pennsylvania, West +Virginia and western Canada. +As of December 31, 2009, we had a drilling fleet that +consisted of 341 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drill pipe and drilling rig components. +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 +also own and invest in oil and natural gas assets as a working +interest owner. Our oil and natural gas interests are located +primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We exited the drilling and +completion fluids services business on January 20, 2010 and +sold substantially all of the assets, other than billed accounts +receivable, of that business. +Industry +Segments +Our revenues, operating profits and identifiable assets have +been primarily attributable to four industry segments: +• +contract drilling services, +• +pressure pumping services, +• +oil and natural gas exploration and production, and. +• +drilling and completion fluids services. +On January 20, 2010, we exited the drilling and completion +fluids services business and ceased operations in that segment. +As a result of the sale of this business, the historical results +of operations for this segment have been reclassified and are +presented as discontinued operations in this Report. +All of our industry segments had operating profits in 2007. In +2008, except for our drilling and completion fluids services +segment, all of our industry segments had operating profits. In +2009, our pressure pumping services and oil and natural gas +exploration and production segments had operating profits and +our contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2009, we had 341 marketable land-based +drilling rigs based in the following regions: +• +73 in west Texas and southeastern New Mexico, +• +100 in north central and east Texas, northern Louisiana and +Mississippi, +• +56 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana and North Dakota), +• +49 in south Texas and southern Louisiana, +2 +Table of Contents +• +28 in the Texas panhandle, Oklahoma and Arkansas, +• +15 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Of these drilling rigs, 107 are electric rigs and 234 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. We also have a substantial inventory of drill pipe and +drilling rig components, which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.3 billion during the last three years on capital +expenditures to (1) build new land drilling rigs and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2009, 2008 and 2007, we spent approximately +$395 million, $361 million and $540 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the specifications of the +rig selected for a particular job. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well +basis or a term basis. +Well-to-well +contracts are generally short-term in nature and cover the +drilling of a single well or a series of wells. Term contracts +are entered into for a specified period of time (frequently one +to three years) and provide for the use of the drilling rig to +drill multiple wells. During 2009, our average number of days to +drill a well (which includes moving to the drill site, rigging +up and rigging down) was approximately 20 days. +Our 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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. Generally, we +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. +Generally, the customers indemnify us against claims that might +arise from other surface and subsurface pollution. Each drilling +contract contains the actual terms setting forth our rights and +obligations and those of the customer, any of which rights and +obligations may deviate from what is customary due to industry +conditions or other factors. +Our drilling contracts provide for payment on a daywork, +footage, or turnkey basis, or a combination thereof. In each +case, we provide the rig and crews. Except for two wells drilled +under footage contracts in 2009, all of the wells drilled during +the years ended December 31, 2009, 2008 and 2007 were +drilled under daywork contracts. Our bid for each job 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. +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. Except for two wells drilled under footage +contracts in 2009, all of the wells we drilled in 2009, 2008 and +2007 were under daywork contracts. +3 +Table of Contents +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor typically assumes certain +risks associated with loss of the well from fire, blowouts and +other risks. We drilled two wells under footage contracts in +2009, and we did not drill any wells under footage contracts in +2008 or 2007. +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed scope of +the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey +contracts in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2009 +2008 +2007 +Average rigs operating per day(1) +91 +254 +244 +Number of rigs operated during the year +243 +315 +338 +Number of wells drilled during the year +1,539 +4,218 +4,237 +Number of operating days(2) +33,394 +93,068 +89,095 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +(2) +Includes standby days under term contracts where revenue was +earned but the rig was not working. The number of these standby +days under term contracts was 2,070 in 2009, 486 in 2008 and +zero in 2007. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2009 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +59 +9 +68 +12,000 to 15,999 +189 +8 +197 +16,000 to 30,000 +73 +— +73 +Totals +321 +20 +341 +At December 31, 2009, we owned and operated 323 trucks and +417 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and generally +enhances the efficiency of our contract drilling operations, +particularly in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, Oklahoma, +Wyoming, Utah, Pennsylvania and western Canada. +4 +Table of Contents +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the well bore. Appalachian Basin wells typically require +cementing services. The cementing process inserts material +between the wall of the well bore and the casing to center and +stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2009 includes equipment used in providing +hydraulic and nitrogen fracturing services as well as cementing +services as follows: +Hydraulic fracturing equipment: +• +20 quintiplex pump trailers (45,000 hydraulic horsepower), +• +69 triplex pumper trucks (82,800 hydraulic horsepower), +• +35 blender trucks, +• +4 blender trailers, +• +32 bulk acid trucks/acid pumper trucks, +• +70 bulk sand trucks, +• +19 sand pneumatic trucks, +• +6 sand pneumatic trailers, +• +15 flatbed material trucks, +• +30 connection trucks, +• +1 shale fracturing hydration trailer, +• +3 shale fracturing manifold trailers, +• +1 shale fracturing iron trailer, +• +15 shale fracturing sand field bins with conveyors, and +• +3 shale fracturing large conveyors. +Nitrogen fracturing equipment: +• +59 nitrogen pumper trucks (35,400 hydraulic horsepower), +• +30 bulk nitrogen trucks, and +• +9 bulk nitrogen tractor trailer combinations, +Cementing equipment: +• +44 cement pumper trucks, and +• +51 bulk cement trucks. +In addition to the equipment listed above, we had 45 tractors at +December 31, 2009 which are used in all of the lines of +business within our pressure pumping segment. +Oil and +Natural Gas Interests +We have been engaged in the development, exploration, +acquisition and production of oil and natural gas. Through +October 31, 2007, we served as operator with respect to +several properties and were actively involved in +5 +Table of Contents +the development, exploration, acquisition and production of oil +and natural gas. Effective November 1, 2007, we sold the +related operations portion of our exploration and production +business, which was the portion of our business that actively +managed the development, exploration, acquisition and production +of oil and natural gas. We continue to own and invest in oil and +natural gas assets as a working interest owner. Our oil and +natural gas interests are located primarily in producing regions +of Texas and New Mexico. +Drilling +and Completion Fluids Operations +Prior to exiting the business in January 2010, we provided +drilling fluids, completion fluids and related services to oil +and natural gas operators offshore in the Gulf of Mexico and on +land in Texas, New Mexico, Oklahoma and Louisiana. +Customers +The customers of each of our oil and natural gas service +business segments are oil and natural gas operators. Our +customer base includes both major and independent oil and +natural gas operators. During 2009, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly +competitive. Historically, available equipment used in these +businesses has frequently exceeded demand in our markets. The +price for our services is a key competitive factor in our +markets, in part because equipment used in our businesses can be +moved from one area to another in response to market conditions. +In addition to price, we believe availability and condition of +equipment, quality of personnel, service quality and safety +record are key factors in determining which contractor is +awarded a job in the markets in which we operate. We expect that +the market for land drilling and pressure pumping services will +continue to be competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations in the +United States and Canada have not required the expenditure of +significant resources outside the ordinary course of business. +We do not anticipate any material capital expenditures for +environmental control facilities or extraordinary expenditures +to comply with environmental rules and regulations in the +foreseeable future. However, compliance costs under existing +laws or under any new requirements could become material, and we +could incur liability in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. Federal, state, foreign and +local environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 operated by us or our +predecessors which may have resulted, or may result, in soil and +groundwater contamination in certain locations. Any +contamination found on, under or originating from the properties +may be subject to remediation requirements under Federal, state, +foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or +operators. In addition, it is possible we could be held +responsible for oil and natural gas properties in which we own +an interest but are not the operator. +6 +Table of Contents +Some of the environmental laws and regulations that are +applicable to our business operations are discussed in the +following paragraphs, but the discussion does not cover all +environmental laws and regulations that govern our operations. +In the United States, the Federal Comprehensive Environmental +Response Compensation and Liability Act of 1980, as amended, +commonly known as CERCLA, and comparable state statutes impose +strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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 working interest in +oil and natural gas properties in each of the areas in which +these interests are located. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may +subject a responsible party, such as us, to civil or criminal +actions. Although the liability for owners and operators is the +same under the Federal Water Pollution Act, the damages +recoverable under the Oil Pollution Act are potentially much +greater and can include natural resource damages. +In Canada, a variety of Canadian federal, provincial and +municipal laws and regulations impose, among other things, +restrictions, liabilities and obligations in connection with the +generation, handling, use, storage, transportation, treatment +and disposal of hazardous substances and wastes and in +connection with spills, releases and emissions of various +substances to the environment. These laws and regulations also +require that facility sites and other properties associated with +our operations be operated, maintained, abandoned and reclaimed +to the satisfaction of applicable regulatory authorities. In +addition, new projects or changes to existing projects may +require the submission and approval of environmental assessments +or permit applications. These laws and regulations are subject +to frequent change, and the clear trend is to place increasingly +stringent limitations on activities that may affect the +environment. +Our operations are also subject to Federal, state, foreign and +local laws, rules and regulations for the control of air +emissions, including the Federal Clean Air Act and the Canadian +Environmental Protection Act. We are aware of the increasing +focus of local, state, national and international regulatory +bodies on greenhouse gas (GHG) emissions and climate change +issues. We are also aware of legislation proposed by United +States lawmakers and the Canadian legislature to reduce GHG +emissions, as well as GHG emissions regulations enacted by the +U.S. Environmental Protection Agency and the Canadian +provinces of Alberta and British Columbia. We will continue to +monitor and assess any new policies, legislation or regulations +in the areas where we operate to determine the impact of GHG +emissions and climate change on our operations and take +appropriate actions, where necessary. Any direct and +7 +Table of Contents +indirect costs of meeting these requirements may adversely +affect our business, results of operations and financial +condition. +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, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +insurance for fire, windstorm and other risks of physical loss +to our rigs and other assets, +• +employer’s liability, +• +automobile liability, +• +commercial general liability insurance, and +• +workers compensation insurance. +We believe that we are adequately insured for bodily injury and +property damage to others with respect to our operations. Such +insurance, however, may not be sufficient to protect us against +liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. Such insurance does not, however, cover the +full replacement cost of the rigs, and we do not carry insurance +against loss of earnings resulting +8 +Table of Contents +from such damage. In view of the difficulties that may be +encountered in renewing such insurance at reasonable rates, no +assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +Employees +We had approximately 4,200 full-time employees at +December 31, 2009. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada and, to a +lesser extent, our pressure pumping operations in the +Appalachian Basin, are subject to slow periods of activity +during the Spring thaw. +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. +Item 1A. +Risk +Factors. +You should consider each of the following factors as well as the +other information in this Report in evaluating our business and +our prospects. Additional risks and uncertainties not presently +known to us or that we currently consider immaterial may also +impair our business operations. If any of the following risks +actually occur, our business and financial results could be +harmed. You should also refer to the other information set forth +in this Report, including our financial statements and the +related notes. +Global +Economic Conditions May Adversely Affect Our Operating +Results. +Since reaching a peak in June 2008, there has been a significant +decline in oil and natural gas prices. Since that time there has +also been a significant deterioration in the global economic +environment. As part of this deterioration, there has been +significant uncertainty in the capital markets and access to +financing has been reduced. Due to these conditions, our +customers reduced or curtailed their drilling programs, which +resulted in a decrease in demand for our services. Furthermore, +these factors have resulted in, and could continue to result in, +certain of our customers experiencing an inability to pay +suppliers, including us, if they are not able to access capital +to fund their operations. Although the significant deterioration +in the global economic environment appears to have recently +stabilized to some degree, our customers may not substantially +increase their drilling programs unless there is more certainty +about global economic prospects. These conditions could have a +material adverse effect on our business, financial condition, +cash flows and results of operations. +9 +Table of Contents +We are +Dependent on the Oil and Natural Gas Industry and Market Prices +for Oil and Natural Gas. Declines in Oil and Natural Gas Prices +Have Adversely Affected Our Operating Results. +Our revenue, profitability, financial condition and rate of +growth are substantially dependent upon prevailing prices for +natural gas and, to a lesser extent, oil. For many years, oil +and natural gas prices and markets have been extremely volatile. +Prices are affected by: +• +market supply and demand, +• +international military, political and economic +conditions, and +• +the ability of the Organization of Petroleum Exporting +Countries, commonly known as OPEC, to set and maintain +production and price targets. +All of these factors are beyond our control. During 2008, the +monthly average market price of natural gas peaked in June at +$13.06 per Mcf before rapidly declining to an average of $5.99 +per Mcf in December 2008. In 2009, the monthly average market +price of natural gas declined further to a low of $3.06 per Mcf +in September. This decline in the market price of natural gas +resulted in our customers significantly reducing their drilling +activities beginning in the fourth quarter of 2008, and drilling +activities remained low throughout 2009. This reduction in +demand combined with the reactivation and construction of new +land drilling rigs in the United States during the last several +years has resulted in excess capacity compared to demand. As a +result of these factors, our average number of rigs operating +has declined significantly. We expect oil and natural gas prices +to continue to be volatile and to affect our financial +condition, operations and ability to access sources of capital. +Low market prices for natural gas would likely result in demand +for our drilling rigs remaining low and adversely affect our +operating results, financial condition and cash flows. +A +General Excess of Operable Land Drilling Rigs and Increasing Rig +Specialization May Adversely Affect Our Utilization and Profit +Margins. +The North American land drilling industry has experienced +periods of downturn in demand over the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins and, +at times, have sustained losses during the downturn periods. +In addition, unconventional resource plays have substantially +increased recently and some drilling rigs are not capable of +drilling these wells efficiently. Accordingly, the utilization +of some older technology drilling rigs may be hampered by their +lack of capability to successfully compete for this work. Other +ongoing factors which could continue to adversely affect +utilization rates and pricing, even in an environment of high +oil and natural gas prices and increased drilling activity, +include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new drilling rigs. +Construction of new drilling rigs increased significantly during +the last five years. The addition of new drilling rigs to the +market and the recent decrease in demand has resulted in excess +capacity. We cannot predict either the future level of demand +for our contract drilling services or future conditions in the +oil and natural gas contract drilling business. +Shortages +of Drill Pipe, Replacement Parts and Other Related Rig Equipment +Adversely Affects Our Operating Results. +During periods of increased demand for drilling services, the +industry has experienced shortages of drill pipe, replacement +parts and other related rig equipment. These shortages can cause +the price of these items to increase significantly and require +that orders for the items be placed well in advance of expected +use. In addition, any interruption in supply due to vendor or +other issues could result in significant delays in delivery of +equipment. These +10 +Table of Contents +price increases and delays in delivery may require us to +increase capital and repair expenditures in our contract +drilling segment. Severe shortages or delays in delivery could +limit our ability to operate our drilling rigs. +The +Oil Service Business Segments in Which We Operate Are Highly +Competitive with Excess Capacity, which Adversely Affects Our +Operating Results. +Our land drilling and pressure pumping businesses are highly +competitive. At 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 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. +Labor +Shortages and Rising Labor Costs Adversely Affect Our Operating +Results. +During periods of increasing demand for contract drilling and +pressure pumping services, the industry experiences shortages of +qualified personnel. During these periods, our ability to +attract and retain sufficient qualified personnel to market and +operate our drilling rigs and pressure pumping equipment is +adversely affected, which negatively impacts both our operations +and profitability. Operationally, it is more difficult to hire +qualified personnel, which adversely affects our ability to +mobilize inactive rigs and pressure pumping equipment in +response to the increased demand for such services. +Additionally, wage rates for drilling and pressure pumping +personnel are likely to increase during periods of increasing +demand, resulting in higher operating costs. +Growth +Through the Building of New Rigs and Rig Acquisitions are Not +Assured. +We have increased our drilling rig fleet in the past through +mergers, acquisitions and rig construction. The land drilling +industry has experienced significant consolidation, and there +can be no assurance that acquisition opportunities will be +available in the future. We are also likely to continue to face +intense competition from other companies for available +acquisition opportunities. In addition, because improved +technology has enhanced the ability to recover oil and natural +gas, contract drillers may continue to build new, high +technology rigs. +There can be no assurance that we will: +• +have sufficient capital resources to complete additional +acquisitions or build new rigs, +• +successfully integrate additional drilling rigs or other assets, +• +effectively manage the growth and increased size of our +organization and drilling fleet, +• +successfully deploy idle, stacked or additional rigs, +• +maintain the crews necessary to operate additional drilling +rigs, or +• +successfully improve our financial condition, results of +operations, business or prospects as a result of any completed +acquisition or the building of new drilling rigs. +We may incur substantial indebtedness to finance future +acquisitions or build new drilling rigs and also may issue +equity, convertible or debt securities in connection with any +such acquisitions or building program. Debt service requirements +could represent a significant burden on our results of +operations and financial condition, and the issuance of +additional equity would be dilutive to existing stockholders. +Also, continued growth could strain our management, operations, +employees and other resources. +11 +Table of Contents +The +Nature of our Business Operations Presents Inherent Risks of +Loss that, if not Insured or Indemnified Against, Could +Adversely Affect Our Operating Results. +Our operations are subject to many hazards inherent in the +contract drilling and pressure pumping businesses, which in turn +could cause personal injury or death, work stoppage, or serious +damage to our equipment. Our operations could also cause +environmental and reservoir damages. We maintain insurance +coverage and have indemnification agreements with many of our +customers. However, there is no assurance that such insurance or +indemnification agreements would adequately protect us against +liability or losses from all consequences of these hazards. +Additionally, there can be no assurance that insurance would be +available to cover any or all of these risks, or, even if +available, that insurance premiums or other costs would not rise +significantly in the future, so as to make the cost of such +insurance prohibitive. Incurring a liability for which we are +not fully insured or indemnified could materially affect our +business, financial condition and results of operations. +We have also 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, general +liability and equipment insurance coverages. +Violations +of Environmental Laws and Regulations Could Materially Adversely +Affect Our Operating Results. +All of our operations and facilities are subject to numerous +Federal, state, foreign and local environmental laws, rules and +regulations, including, without limitation, laws concerning the +containment and disposal of hazardous substances, oil field +waste and other waste materials, the use of underground storage +tanks, and the use of underground injection wells. The cost of +compliance with these laws and regulations could be substantial. +A failure to comply with these requirements could expose us to +substantial civil and criminal penalties. In addition, +environmental laws and regulations in the United States and +Canada impose a variety of requirements 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 these laws and regulations. +We are aware of the increasing focus of local, state, national +and international regulatory bodies on GHG emissions and climate +change issues. We are also aware of legislation proposed by +United States lawmakers and the Canadian legislature to reduce +GHG emissions, as well as GHG emissions regulations enacted by +the U.S. Environmental Protection Agency and the Canadian +provinces of Alberta and British Columbia. We will continue to +monitor and assess any new policies, legislation or regulations +in the areas where we operate to determine the impact of GHG +emissions and climate change on our operations and take +appropriate actions, where necessary. Any direct and indirect +costs of meeting these requirements may adversely affect our +business, results of operations and financial condition. +Anti-takeover +Measures in Our Charter Documents and Under State Law Could +Discourage an Acquisition and Thereby Affect the Related +Purchase Price. +We are a Delaware corporation subject to the Delaware General +Corporation Law, including Section 203, an anti-takeover +law. We have also enacted certain anti-takeover measures, +including a stockholders’ rights plan. In addition, our +Board of Directors has the authority to issue up to one million +shares of preferred stock and to determine the price, rights +(including voting rights), conversion ratios, preferences and +privileges of that stock without further vote or action by the +holders of the common stock. As a result of these measures and +others, potential acquirers might find it more difficult or be +discouraged from attempting to effect an acquisition transaction +with us. This may deprive holders of our securities of certain +opportunities to sell or otherwise dispose of the securities at +above-market prices pursuant to any such transactions. +Item 1B. +Unresolved +Staff Comments. +None. +12 +Table of Contents +Item 2. +Properties +Our corporate headquarters comprises approximately +12,000 square feet of leased office space, and is located +at 450 Gears Road, Suite 500, Houston, Texas. Our telephone +number at that address is +(281) 765-7100. +Our primary administrative office is located in Snyder, Texas +and includes approximately 37,000 square feet of office and +storage space. +Contract Drilling Operations — Our drilling +services are supported by several offices and yard facilities +located throughout our areas of operations, including Texas, New +Mexico, Oklahoma, Colorado, Utah, Wyoming, Pennsylvania and +western Canada. +Pressure Pumping — Our pressure pumping +services are supported by several offices and yard facilities +located throughout our areas of operations including +Pennsylvania, Ohio, New York, West Virginia, Kentucky, Tennessee +and Colorado. +Oil and Natural Gas Working Interests — Our +interests in oil and natural gas properties are primarily +located in Texas and New Mexico. +We own our administrative offices in Snyder, Texas, as well as +several of our other facilities. We also lease a number of +facilities, and we do not believe that any one of the leased +facilities is individually material to our operations. We +believe that our existing facilities are suitable and adequate +to meet our needs. +Item 3. +Legal +Proceedings. +We are party to various legal proceedings arising in the normal +course of our business. We do not believe that the outcome of +these proceedings, either individually or in the aggregate, will +have a material adverse effect on our results of operations, +cash flows or financial condition. +Item 4. +Submission +of Matters to a Vote of Security Holders. +None. +13 +Table of Contents +PART II +Item 5. +Market +for Registrant’s Common Equity, Related Stockholder Matters +and Issuer Purchases of Equity Securities. +(a) +Market +Information +Our common stock, par value $0.01 per share, is publicly traded +on the Nasdaq Global Select Market and is quoted under the +symbol “PTEN.” Our common stock is included in the +S&P MidCap 400 Index and several other market indices. The +following table provides high and low sales prices of our common +stock for the periods indicated: +High +Low +2008: +First quarter +$ +26.38 +$ +17.40 +Second quarter +36.40 +25.71 +Third quarter +37.45 +17.85 +Fourth quarter +19.64 +8.64 +2009: +First quarter +$ +13.50 +$ +7.49 +Second quarter +15.95 +8.56 +Third quarter +15.98 +11.38 +Fourth quarter +18.07 +14.20 +(b) +Holders +As of February 17, 2010, there were approximately 1,700 holders +of record of our common stock. +(c) +Dividends +We paid cash dividends during the years ended December 31, +2008 and 2009 as follows: +Per Share +Total +(in thousands) +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +On February 10, 2010, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.05 per +share to be paid on March 30, 2010 to holders of record as +of March 15, 2010. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +14 +Table of Contents +(d) +Securities +Authorized for Issuance Under Equity Compensation +Plans +Equity compensation plan information as of December 31, +2009 follows: +Equity Compensation Plan Information +Number of +Number of +Securities +Securities to +Remaining Available +be Issued upon +for Future Issuance +Exercise of +Weighted-Average +under Equity +Outstanding +Exercise Price +Compensation Plans +Options, +of Outstanding +(Excluding Securities +Warrants and +Options, Warrants +Reflected in +Plan Category +Rights +and Rights +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved by security holders(1) +6,627,634 +$ +20.50 +2,545,524 +Equity compensation plans not approved by security holders(2) +214,136 +$ +9.97 +— +Total +6,841,770 +$ +20.17 +2,545,524 +(1) +The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended (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, officers +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. +(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 officers and directors. No Incentive Stock +Options could be awarded under the 2001 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. +15 +Table of Contents +(e) +Performance +Graph +The following graph compares the cumulative stockholder return +of our common stock for the period from December 31, 2004 +through December 31, 2009, with the cumulative total return +of the Standard & Poors 500 Stock Index, the +Standard & Poors MidCap Index, the Oilfield Service +Index and a peer group determined by us. Our 2008 peer group +consists of BJ Services Company, Bronco Drilling Company, Inc., +Helmerich & Payne, Inc., Nabors Industries, Ltd., +Pioneer Drilling Co., Superior Well Services, Inc. and Unit +Corp. We evaluated our peer group for 2009 and determined that +it was appropriate to remove Unit Corp. from the peer group as +their drilling revenue as a percentage of total revenue had +fallen to a level that was no longer comparable to ours. All of +the companies in our peer group are providers of land-based +drilling or pressure pumping services. The graph assumes +investment of $100 on December 31, 2004 and reinvestment of +all dividends. +Fiscal Year Ended December 31, +2004 +2005 +2006 +2007 +2008 +2009 +Company/Index +($) +($) +($) +($) +($) +($) +Patterson-UTI Energy, Inc. +100.00 +170.35 +121.41 +104.04 +63.26 +85.73 +2008 Peer Group Index +100.00 +155.75 +125.07 +117.78 +58.99 +94.96 +2009 Peer Group Index +100.00 +156.66 +124.84 +117.42 +57.93 +93.38 +S&P 500 Stock Index +100.00 +104.91 +121.48 +128.16 +80.74 +102.11 +Oilfield Service Index (OSX) +100.00 +149.90 +171.09 +251.13 +102.21 +164.12 +S&P MidCap Index +100.00 +112.56 +124.17 +134.08 +85.50 +117.46 +The foregoing graph is based on historical data and is not +necessarily indicative of future performance. This graph shall +not be deemed to be “soliciting material” or to be +“filed” with the SEC or subject to Regulations 14A or +14C under the Exchange Act or to the liabilities of +Section 18 under such Act. +Item 6. +Selected +Financial Data. +Our selected consolidated financial data as of December 31, +2009, 2008, 2007, 2006 and 2005, and for each of the five years +in the period ended December 31, 2009 should be read in +conjunction with “Management’s Discussion and Analysis +of Financial Condition and Results of Operations” and the +Consolidated Financial Statements and related Notes thereto, +included as Items 7 and 8, respectively, of this Report. +Certain reclassifications have been made to the historical +financial data to conform with the 2009 presentation. Due to the +sale of +16 +Table of Contents +substantially all of the assets of our drilling and completion +fluids business in January 2010, the results of operations for +that business have been reclassified and are presented as +discontinued operations in all periods presented below. +Years Ended December 31, +2009 +2008 +2007 +2006 +2005 +(In thousands, except per share amounts) +Statement of Operations Data: +Operating revenues: +Contract drilling +$ +599,287 +$ +1,804,026 +$ +1,741,647 +$ +2,169,370 +$ +1,485,684 +Pressure pumping +161,441 +217,494 +202,812 +145,671 +93,144 +Oil and natural gas +21,218 +42,360 +41,637 +39,187 +39,616 +Total +781,946 +2,063,880 +1,986,096 +2,354,228 +1,618,444 +Operating costs and expenses: +Contract drilling +357,742 +1,038,327 +963,150 +1,002,001 +776,313 +Pressure pumping +111,414 +132,570 +105,273 +77,755 +54,956 +Oil and natural gas +7,341 +12,793 +10,864 +13,374 +9,566 +Depreciation, depletion and impairment +289,847 +275,990 +246,346 +193,664 +154,025 +Selling, general and administrative +56,621 +58,080 +54,665 +44,544 +30,198 +Embezzlement costs (recoveries) +— +— +(43,955 +) +3,081 +20,043 +Net loss (gain) on asset disposals +3,385 +(4,163 +) +(16,432 +) +3,905 +(1,200 +) +Other operating expenses +3,810 +4,350 +2,875 +5,585 +4,859 +Total +830,160 +1,517,947 +1,322,786 +1,343,909 +1,048,760 +Operating income (loss) +(48,214 +) +545,933 +663,310 +1,010,319 +569,684 +Other income (expense) +(3,341 +) +1,425 +527 +4,657 +3,465 +Income (loss) from continuing operations before income taxes +(51,555 +) +547,358 +663,837 +1,014,976 +573,149 +Income tax expense (benefit) +(17,595 +) +193,490 +229,350 +360,639 +207,706 +Income (loss) from continuing operations +$ +(33,960 +) +$ +353,868 +$ +434,487 +$ +654,337 +$ +365,443 +Income (loss) from continuing operations per common share: +Basic +$ +(0.22 +) +$ +2.29 +$ +2.78 +$ +3.94 +$ +2.14 +Diluted +$ +(0.22 +) +$ +2.27 +$ +2.75 +$ +3.89 +$ +2.11 +Cash dividends per common share +$ +0.20 +$ +0.60 +$ +0.44 +$ +0.28 +$ +0.16 +Weighted average number of common shares outstanding: +Basic +152,069 +153,379 +154,755 +165,159 +170,426 +Diluted +152,069 +154,358 +156,612 +167,200 +172,312 +Balance Sheet Data: +Total assets +$ +2,662,152 +$ +2,712,817 +$ +2,465,199 +$ +2,192,503 +$ +1,795,781 +Borrowings under line of credit +— +— +50,000 +120,000 +— +Stockholders’ equity +2,081,700 +2,126,942 +1,896,030 +1,562,466 +1,367,011 +Working capital +263,960 +338,761 +227,577 +335,052 +382,448 +17 +Table of Contents +Item 7. +Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +Management Overview — We are a leading provider +of contract services to the North American oil and natural gas +industry. Our services primarily involve the drilling, on a +contract basis, of land-based oil and natural gas wells and, to +a lesser extent, pressure pumping services. In addition to the +aforementioned contract services, we also invest, on a working +interest basis, in oil and natural gas properties. For the three +years ended December 31, 2009, our operating revenues +consisted of the following (dollars in thousands): +2009 +2008 +2007 +Contract drilling +$ +599,287 +76 +% +$ +1,804,026 +87 +% +$ +1,741,647 +88 +% +Pressure pumping +161,441 +21 +217,494 +11 +202,812 +10 +Oil and natural gas +21,218 +3 +42,360 +2 +41,637 +2 +$ +781,946 +100 +% +$ +2,063,880 +100 +% +$ +1,986,096 +100 +% +We provide our contract services to oil and natural gas +operators in many of the oil and natural gas producing regions +of North America. Our contract drilling operations are focused +in various regions of Texas, New Mexico, Oklahoma, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, South Dakota, Pennsylvania, and western Canada, while +our pressure pumping services are focused primarily in the +Appalachian Basin. The oil and natural gas properties in which +we hold interests are primarily located in Texas and New Mexico. +Typically, the profitability of our business is most readily +assessed by two primary indicators in our contract drilling +segment: our average number of rigs operating and our average +revenue per operating day. During 2009, our average number of +rigs operating was 91 compared to 254 in 2008 and 244 in 2007. +Our average revenue per operating day was $17,950 in 2009 +compared to $19,380 in 2008 and $19,550 in 2007. We had a +consolidated net loss of $38.3 million for 2009 compared to +consolidated net income of $347 million for 2008. This +decrease was primarily due to our contract drilling segment +experiencing a significant decrease in the average number of +rigs operating as compared to 2008. +Our revenues, profitability and cash flows are highly dependent +upon prevailing prices for natural gas and, to a lesser extent, +oil. During periods of improved commodity prices, the capital +spending budgets of oil and natural gas operators tend to +expand, which generally results in increased demand for our +contract services. Conversely, in periods when these commodity +prices deteriorate, the demand for our contract services +generally weakens and we experience downward pressure on pricing +for our services. Since reaching a peak in June 2008, there has +been a significant decline in oil and natural gas prices. Since +that time there has also been a substantial deterioration in the +global economic environment. As part of this deterioration, +there has been substantial uncertainty in the capital markets +and access to financing has been reduced. Due to these +conditions, our customers reduced or curtailed their drilling +programs, which resulted in a decrease in demand for our +services, as evidenced by the decline in our monthly average +rigs operating from a high of 283 in October 2008 to a low of 60 +in June 2009 before partially recovering to 118 in December +2009. Furthermore, these factors have resulted in, and could +continue to result in, certain of our customers experiencing an +inability to pay suppliers, including us, if they are not able +to access capital to fund their operations. We are also highly +impacted by competition, the availability of excess equipment, +labor issues and various other factors that could materially +adversely affect our business, financial condition, cash flows +and results of operations and which are more fully described +above as “Risk Factors” in Item 1A of this Report. +We believe that the liquidity shown on our balance sheet as of +December 31, 2009, which includes approximately +$264 million in working capital (including +$49.9 million in cash) and approximately $194 million +available under our $240 million revolving credit facility, +together with cash expected to be generated from operations +(including expected income tax refunds in 2010 of approximately +$114 million resulting from the carry-back of net operating +losses), should provide us with sufficient ability to fund our +current plans to build new equipment, make improvements to our +existing equipment, expand into new regions, pay cash dividends +and survive the current downturn in our industry. If we pursue +opportunities for growth that require capital, we believe we +would be able to satisfy these needs through a combination of +working capital, cash generated from operations, borrowing +capacity under our revolving credit facility or additional debt +or equity financing. However, there can be no assurance that +such capital will be available on reasonable terms, if at all. +18 +Table of Contents +Commitments and Contingencies — As of +December 31, 2009, we maintained letters of credit in the +aggregate amount of $46.3 million for the benefit of +various insurance companies as collateral for retrospective +premiums and retained losses which could become payable under +the terms of the underlying insurance contracts. These letters +of credit expire at various times during each calendar year and +are typically renewed annually. As of December 31, 2009, no +amounts had been drawn under the letters of credit. +As of December 31, 2009, we had commitments to purchase +approximately $186 million of major equipment. +Trading and investing — We have not engaged in +trading activities that include high-risk securities, such as +derivatives and non-exchange traded contracts. We invest cash +primarily in highly liquid, short-term investments such as +overnight deposits and money market accounts. +Description of business — We conduct our +contract drilling operations in Texas, New Mexico, Oklahoma, +Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, +Montana, North Dakota, Pennsylvania, West Virginia and western +Canada. For the years ended December 31, 2009, 2008 and +2007, revenue earned in Canada was $45.4 million, +$88.5 million and $72.9 million, respectively. +Additionally, we had long-lived assets located in Canada of +$69.2 million and $67.2 million as of +December 31, 2009 and 2008, respectively. As of +December 31, 2009, we had 341 marketable land-based +drilling rigs. We provide pressure pumping services to oil and +natural gas operators primarily in the Appalachian Basin. These +services consist primarily of well stimulation and cementing for +completion of new wells and remedial work on existing wells. +Prior to the sale of substantially all of the assets of our +drilling fluids business on January 20, 2010, we provided +drilling fluids, completion fluids and related services to oil +and natural gas operators offshore in the Gulf of Mexico and on +land in Texas, New Mexico, Oklahoma and Louisiana. Drilling and +completion fluids are used by oil and natural gas operators +during the drilling process to control pressure when drilling +oil and natural gas wells. Due to our exit from the drilling and +completion fluids business in January 2010, we have presented +the results of that operating segment as discontinued operations +in this Report. We also invest, on a working interest basis, in +oil and natural gas properties. +Critical +Accounting Policies +In addition to established accounting policies, our consolidated +financial statements are impacted by certain estimates and +assumptions made by management. The following is a discussion of +our critical accounting policies pertaining to property and +equipment, oil and natural gas properties, goodwill, revenue +recognition and the use of estimates. +Property and equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our +long-lived assets, including property and equipment, for +impairment whenever events or changes in circumstances indicate +that the carrying values of certain assets may not be recovered +over their estimated remaining useful lives. In connection with +this review, assets are grouped at the lowest level at which +identifiable cash flows are largely independent of other asset +groupings. The cyclical nature of our industry has resulted in +fluctuations in rig utilization over periods of time. Management +believes that the contract drilling industry will continue to be +cyclical and rig utilization will fluctuate. Based on +management’s expectations of future trends, we estimate +future cash flows over the life of the respective assets in our +assessment of impairment. These estimates of cash flows are +based on historical cyclical trends in the industry as well as +management’s expectations regarding the continuation of +these trends in the future. Provisions for asset impairment are +charged against income when estimated future cash flows, on an +undiscounted basis, are less than the asset’s net book +value. Any provision for impairment is measured based on +discounted cash flows. +On a periodic basis, we evaluate our fleet of drilling rigs for +marketability. During 2009 and 2008, in connection with our long +term planning process, we evaluated our then-current fleet of +marketable drilling rigs and identified 23 and 22 rigs, +respectively, that we determined would no longer be marketed as +rigs. Additionally, in 2009, we identified one rig which would +be recommissioned in a different configuration. The components +comprising these rigs were evaluated, and those components with +continuing utility to our other marketed rigs +19 +Table of Contents +were transferred to other rigs or to our yards to be used as +spare equipment. The remaining components of these rigs were +impaired and the associated net book value of $10.5 million +in 2009 and $10.4 million in 2008 was expensed in our +consolidated statements of operations as an impairment charge. +In late 2008, we experienced a significant decrease in the +number of our rigs operating and oil and natural gas prices +decreased significantly. These events were deemed by us to be +triggering events that required us to perform an assessment with +respect to impairment of long-lived assets, including property +and equipment, in our contract drilling segment. With respect to +these long-lived assets, we estimated future cash flows over the +expected life of the long-lived assets, which were comprised +primarily of property and equipment, and determined that, on an +undiscounted basis, expected cash flows exceeded the carrying +value of the long-lived assets. Based on this assessment, no +impairment was indicated. We again performed an assessment with +respect to impairment of long-lived assets in our contract +drilling segment in 2009 based on undiscounted cash flows and +determined that no impairment was indicated. Impairment +considerations in our oil and natural gas segment related to +proved properties are discussed below. We concluded that no +triggering event had occurred with respect to our pressure +pumping segment, as the level of activity and revenue impact in +that segment had not been affected to the same degree as in our +other segments. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made in assessing +the reserves and the economic operating viability of the +respective projects. If no progress has been made in assessing +the reserves and the economic operating viability of a project +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 field. +We review our proved oil and natural gas properties for +impairment when a triggering event occurs such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on our +expectation of future commodity prices over the lives of the +respective fields. These estimates are then reviewed by an +independent petroleum engineer. If the net book value of a field +exceeds its undiscounted cash flow estimate, impairment expense +is measured and recognized as the difference between its net +book value and discounted cash flow. The discounted cash flow +estimates used in measuring impairment are based on our +expectations of future commodity prices over the life of the +respective field. Unproved oil and natural gas properties are +reviewed quarterly to assess potential impairment. The 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 results from downward revisions in reserve estimates of +proved properties and amounted to approximately +$3.7 million, $4.4 million and $3.9 million for +the years ended December 31, 2009, 2008 and 2007, +respectively, is included in depreciation, depletion and +impairment in the accompanying consolidated statements of +operations. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. As such, +we assess impairment of our goodwill annually as of December 31 +or on an interim basis if events or circumstances indicate that +the fair value of the asset has decreased below its carrying +value. Goodwill impairment testing is performed at the level of +our reporting units. Our reporting units have been determined to +be the same as our operating segments. +In connection with our annual assessment of potential impairment +of goodwill, we compare the fair value of the reporting unit +with its carrying value. If the fair value exceeds the carrying +value, no impairment is indicated. If the carrying value exceeds +the fair value, we measure any impairment of goodwill in that +reporting unit by allocating the fair value to the identifiable +assets and liabilities of the reporting unit based on their +respective fair +20 +Table of Contents +values. Any excess unallocated fair value would equal the +implied fair value of goodwill, and if that amount is below the +carrying value of goodwill, an impairment charge is recognized. +In connection with our annual goodwill impairment assessment +performed as of December 31, 2008, we performed an +impairment test of goodwill recorded in our contract drilling +and drilling and completion fluids reporting units. In light of +the adverse market conditions affecting our common stock price +beginning in the fourth quarter of 2008 and continuing into +2009, including a significant decrease in the number of our rigs +operating and a significant decline in oil and natural gas +commodity prices, we utilized a discounted cash flow methodology +to estimate the fair values of our reporting units. In +completing the first step of our analysis, we used a three-year +projection of discounted cash flows, plus a terminal value +determined using the constant growth method to estimate the fair +value of our reporting units. In developing these fair value +estimates, we applied key assumptions, including an assumed +discount rate of 13.99% for all reporting units, an assumed +long-term growth rate of 3.50% for the contract drilling +reporting unit and an assumed long-term growth rate of 2.00% for +the drilling and completion fluids reporting unit. +Based on the results of the first step of the impairment test in +2008, we concluded that no impairment was indicated in the +contract drilling reporting unit as the estimated fair value of +that reporting unit exceeded its carrying value. An impairment +was indicated in our drilling and completion fluids reporting +unit as the estimated fair value of that reporting unit was less +than its carrying value. In validating this conclusion, we +considered the results of our long-lived asset impairment tests +and performed sensitivity analyses of the key assumptions used +in deriving the respective fair values of our reporting units. +We then performed the second step of the analysis of our +drilling and completion fluids reporting unit, which included +allocating the estimated fair value to the identifiable tangible +and intangible assets and liabilities of this reporting unit +based on their respective values. This allocation indicated no +residual value for goodwill, and accordingly we recorded an +impairment charge of $9.964 million in our +December 31, 2008 statement of operations. We exited +the drilling and completion fluids business on January 20, +2010, and the 2008 impairment charge is included in our loss +from discontinued operations in our statement of operations for +the year ended December 31, 2008. +We again performed our annual goodwill impairment assessment as +of December 31, 2009 related to the remaining +$86.2 million in goodwill recorded in our contract drilling +reporting unit. In completing the first step of our analysis, we +used a three-year projection of discounted cash flows, plus a +terminal value determined using the constant growth method to +estimate the fair value of our reporting unit. In developing +this fair value estimate, we applied key assumptions, including +an assumed discount rate of 15.42% and an assumed long-term +growth rate of 3.50%. Based on the results of the first step of +the impairment test in 2009, we concluded that no impairment was +indicated in our contract drilling reporting unit as the +estimated fair value of that reporting unit exceeded its +carrying value. +In the event that market conditions weaken, we may be required +to record an impairment of goodwill in our contract drilling +reporting unit in the future, and such impairment could be +material. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting. 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 total +revenues. We recognize reimbursements received from third +parties for +out-of-pocket +expenses incurred as revenues and account for these +out-of-pocket +expenses as direct costs. Except for two wells drilled under +footage contacts in 2009, all of the wells we drilled in 2009, +2008 and 2007 were drilled under daywork contracts. +Use of estimates — The preparation of financial +statements in conformity with accounting principles generally +accepted in the United States of America requires management to +make certain estimates and assumptions that affect the reported +amounts of assets and liabilities and disclosures of contingent +assets and liabilities at the date of +21 +Table of Contents +the financial statements and the reported amounts of revenues +and expenses during the reporting period. Actual results could +differ from such estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation and depletion, +• +goodwill and long-lived asset impairments, and +• +reserves for self-insured levels of insurance coverage. +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. +Liquidity +and Capital Resources +As of December 31, 2009, we had working capital of +$264 million, including cash and cash equivalents of +$49.9 million. During 2009, our sources of cash flow +included: +• +$454 million from operating activities, +• +$3.4 million in proceeds from the disposal of property and +equipment, and +During 2009, we used $30.7 million to pay dividends on our +common stock, $6.2 million to pay issuance costs related to +our revolving credit facility, $1.6 million to repurchase +shares of our common stock and $453 million: +• +to build new drilling rigs, +• +to make capital expenditures for the betterment and +refurbishment of our drilling rigs, +• +to acquire and procure drilling equipment and facilities to +support our drilling operations, +• +to fund capital expenditures for our pressure pumping +segment, and +• +to fund investments in oil and natural gas properties on a +working interest basis. +We paid cash dividends during the year ended December 31, +2009 as follows: +Per Share +Total +(In thousands) +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +On February 10, 2010, our Board of Directors approved a +cash dividend on our common stock in the amount of $0.05 per +share to be paid on March 30, 2010 to holders of record as +of March 15, 2010. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +On August 1, 2007, our Board of Directors approved a stock +buyback program (“Program”), authorizing purchases of +up to $250 million of our common stock in open market or +privately negotiated transactions. During the year ended +December 31, 2009, we purchased 5,715 shares of our +common stock under the Program at a cost of approximately +$79,000. As of December 31, 2009, we are authorized to +purchase approximately $113 million of our outstanding +common stock under the Program. +We have an unsecured revolving credit facility with a maximum +borrowing and letter of credit capacity of $240 million. +Interest is paid on the outstanding principal amount of +borrowings under the revolving credit facility at a floating +rate based on, at our election, LIBOR or a base rate. The margin +on LIBOR loans ranges from 3.00% to +22 +Table of Contents +4.00% and the margin on base rate loans ranges from 2.00% to +3.00%, based on our debt to capitalization ratio. Any +outstanding borrowings must be repaid at maturity on +January 31, 2012 and letters of credit may remain in effect +up to six months after such maturity date. As of +December 31, 2009, we had no borrowings outstanding under +the revolving credit facility. We had $46.3 million in +letters of credit outstanding at December 31, 2009, and as +a result, had available borrowing capacity of approximately +$194 million at such date. +There are customary representations, warranties, restrictions +and covenants associated with the revolving credit facility. +Financial covenants provide for a maximum debt to capitalization +ratio and a minimum interest coverage ratio. As of +December 31, 2009, the maximum debt to capitalization ratio +was 35% and the minimum interest coverage ratio was 3.00 to 1. +We were in compliance with these financial covenants as of +December 31, 2009. We do not expect that the restrictions +and covenants will impact our ability to operate or react to +opportunities that might arise. +We believe that the current level of cash, short-term +investments and borrowing capacity available under our revolving +credit facility, together with cash expected to be generated +from operations (including expected income tax refunds in 2010 +of approximately $114 million resulting from the carry-back +of net operating losses), should be sufficient to meet our +current capital needs. From time to time, opportunities to +expand our business, including acquisitions and the building of +new rigs are evaluated. The timing, size or success of any +acquisition and the associated capital commitments are +unpredictable. If we pursue opportunities for growth that +require capital, we believe we would be able to satisfy these +needs through a combination of working capital, cash generated +from operations, borrowing capacity under our revolving credit +facility or additional debt or equity financing. However, there +can be no assurance that such capital will be available on +reasonable terms, if at all. +Contractual +Obligations +The following table presents information with respect to our +contractual obligations as of December 31, 2009 (dollars in +thousands): +Payments due by period +Less Than 1 +More Than 5 +Total +Year +1-3 Years +3-5 Years +Years +Borrowings under revolving credit facility(1) +$ +— +$ +— +$ +— +$ +— +$ +— +Commitments to purchase equipment(2) +186,220 +186,220 +— +— +— +$ +186,220 +$ +186,220 +$ +— +$ +— +$ +— +(1) +No borrowings were outstanding on our revolving credit facility +as of December 31, 2009. Our revolving credit facility +matures on January 31, 2012. +(2) +Represents commitments to purchase major equipment to be +delivered in 2010 based on expected delivery dates. +Off-Balance +Sheet Arrangements +We had no off-balance sheet arrangements at December 31, +2009. +23 +Table of Contents +Results +of Operations +Comparison +of the years ended December 31, 2009 and 2008 +The following tables summarize operations by business segment +for the years ended December 31, 2009 and 2008: +Year Ended December 31, +Contract Drilling +2009 +2008 +% Change +(Dollars in thousands) +Revenues +$ +599,287 +$ +1,804,026 +(66.8 +)% +Direct operating costs +$ +357,742 +$ +1,038,327 +(65.5 +)% +Selling, general and administrative +$ +4,340 +$ +5,363 +(19.1 +)% +Depreciation and impairment +$ +248,424 +$ +239,700 +3.6 +% +Operating income (loss) +$ +(11,219 +) +$ +520,636 +N/A +% +Operating days +33,394 +93,068 +(64.1 +)% +Average revenue per operating day +$ +17.95 +$ +19.38 +(7.4 +)% +Average direct operating costs per operating day +$ +10.71 +$ +11.16 +(4.0 +)% +Average rigs operating +91 +254 +(64.2 +)% +Capital expenditures +$ +395,376 +$ +360,645 +9.6 +% +The demand for our contract drilling services is impacted by the +market price of natural gas and, to a lesser extent, oil. The +reactivation and construction of new land drilling rigs in the +United States in recent years has also contributed to an excess +capacity of land drilling rigs compared to demand. The average +market price of natural gas for each of the fiscal quarters and +full years in 2009 and 2008 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2008: +Average natural gas price(1) +$ +8.92 +$ +11.74 +$ +9.28 +$ +6.60 +$ +9.13 +2009: +Average natural gas price(1) +$ +4.71 +$ +3.82 +$ +3.26 +$ +4.46 +$ +4.06 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +Revenues and direct operating costs decreased in 2009 compared +to 2008 primarily as a result of a decrease in the number of +operating days. The decrease in operating days was due to +decreased demand largely caused by lower commodity prices for +natural gas and oil. Our average number of rigs operating during +2009 included an average of approximately six rigs under term +contracts that earned standby revenues of $22.3 million. +This represented an increase from an average of approximately +one rig under term contract that earned standby revenues of +$4.7 million in 2008. Rigs on standby earn a discounted +dayrate as they do not have crews and have lower costs. We +recognized approximately $8.0 million of revenues during +2009 from the early termination of drilling contracts compared +to approximately $1.3 million in 2008. Average revenue per +operating day decreased in 2009 primarily due to decreases in +dayrates for rigs that were operating in the spot market and the +expiration of term contracts that were entered into at higher +rates. Average direct operating costs per operating day +decreased in 2009 primarily due to decreases in labor and repair +costs. Significant capital expenditures were incurred in 2009 +and 2008 to build new drilling rigs, to modify and upgrade our +drilling rigs and to acquire additional related equipment such +as drill pipe, drill collars, engines, fluid circulating +systems, rig hoisting systems and safety enhancement equipment. +Depreciation and impairment expense includes approximately +$10.5 million in 2009 and approximately $10.4 million +in 2008 related to the impairment of drilling equipment +primarily related to drilling rigs that were removed from our +24 +Table of Contents +marketable fleet. We removed 23 rigs from our marketable fleet +in 2009 and removed 22 rigs from our marketable fleet in 2008. +Depreciation expense increased as a result of capital +expenditures. +Year Ended December 31, +Pressure Pumping +2009 +2008 +% Change +(Dollars in thousands) +Revenues +$ +161,441 +$ +217,494 +(25.8 +)% +Direct operating costs +$ +111,414 +$ +132,570 +(16.0 +)% +Selling, general and administrative +$ +21,421 +$ +23,305 +(8.1 +)% +Depreciation +$ +27,589 +$ +19,600 +40.8 +% +Operating income +$ +1,017 +$ +42,019 +(97.6 +)% +Total jobs +7,265 +12,900 +(43.7 +)% +Average revenue per job +$ +22.22 +$ +16.86 +31.8 +% +Average direct operating costs per job +$ +15.34 +$ +10.28 +49.2 +% +Capital expenditures +$ +43,144 +$ +61,289 +(29.6 +)% +Our customers have increased their focus on the emerging +development of unconventional reservoirs in the Appalachian +Basin and the larger jobs associated therewith. As a result of +this focus on unconventional reservoirs and lower commodity +prices, we experienced a decrease in smaller traditional +pressure pumping jobs, which contributed to the overall decrease +in the number of total jobs. Revenues and direct operating costs +decreased as a result of the decrease in the number of total +jobs. Increased average revenue per job reflects an increase in +the proportion of larger jobs to total jobs, which was driven by +demand for services associated with unconventional reservoirs, +partially offset by the impact of reduced pricing. Average +direct operating costs per job increased due to the increase in +larger jobs and as a result of fixed costs being spread over a +significantly reduced number of total jobs. In anticipation of +increased activity associated with the unconventional reservoirs +in the Appalachian Basin, we have added facilities, equipment +and personnel in recent years. Delays in the development of +these reservoirs and lower commodity prices have caused a slower +increase in customer activity than we had expected, negatively +impacting the profitability of this business. Selling, general +and administrative expenses decreased primarily as a result of +cost containment efforts during the downturn in the industry. +Significant capital expenditures have been incurred in recent +years to add capacity. Depreciation expense increased as a +result of capital expenditures. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2009 +2008 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +21,218 +$ +42,360 +(49.9 +)% +Direct operating costs +$ +7,341 +$ +12,793 +(42.6 +)% +Depreciation, depletion and impairment +$ +12,927 +$ +15,856 +(18.5 +)% +Operating income +$ +950 +$ +13,711 +(93.1 +)% +Capital expenditures +$ +7,341 +$ +22,981 +(68.1 +)% +Average net daily oil production (Bbls) +761 +801 +(5.0 +)% +Average net daily gas production (Mcf) +3,225 +3,755 +(14.1 +)% +Average oil sales price (per Bbl) +$ +58.09 +$ +98.70 +(41.1 +)% +Average gas sales price (per Mcf) +$ +4.32 +$ +9.77 +(55.8 +)% +Revenues decreased due to lower average sales prices and lower +average net daily production of oil and natural gas. Average net +daily oil and natural gas production decreased primarily due to +production declines on existing wells. Direct operating costs +decreased primarily due to decreases in seismic expenses as well +as decreased production taxes and other production costs. +Depreciation, depletion and impairment expense in 2009 includes +approximately $3.7 million incurred to impair certain oil +and natural gas properties compared to approximately +$4.4 million incurred to impair certain oil and natural gas +properties in 2008. Depletion expense decreased approximately +$2.3 million primarily due to lower production and the +impact of decreases in the carrying value of +25 +Table of Contents +properties resulting from previous impairment charges. Capital +expenditures decreased in 2009 as a result of declines in +commodity prices. +Year Ended December 31, +Corporate and Other +2009 +2008 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +30,860 +$ +29,412 +4.9 +% +Depreciation +$ +907 +$ +834 +8.8 +% +Other operating expenses +$ +3,810 +$ +4,350 +(12.4 +)% +Net (gain) loss on asset disposals +$ +3,385 +$ +(4,163 +) +N/A +% +Interest income +$ +381 +$ +1,553 +(75.5 +)% +Interest expense +$ +4,148 +$ +630 +558.4 +% +Other income +$ +426 +$ +502 +(15.1 +)% +Capital expenditures +$ +6,785 +$ +511 +1,227.8 +% +Selling, general and administrative expense increased in 2009 +primarily as a result of increased professional fees. Other +operating expenses decreased due to a decrease in bad debt +expense. Gains and losses on the disposal of assets are treated +as part of our corporate activities because such transactions +relate to corporate strategy decisions of our executive +management group. Losses on asset disposals in 2009 were +primarily related to the disposal of contract drilling +equipment. Gains on asset disposals in 2008 were primarily +related to gains on the sale of contract drilling equipment and +the sale of oil and natural gas properties. Interest expense +increased in 2009 due to the amortization of revolving credit +facility issuance costs and increased fees associated with +outstanding letters of credit and the unused portion of the +revolving credit facility. Capital expenditures increased in +2009 due to the purchase and ongoing implementation of a new +enterprise resource planning system. +Year Ended December 31, +Discontinued Operations: +2009 +2008 +% Change +(Dollars in thousands) +Drilling and completion fluids revenue +$ +79,786 +$ +145,246 +(45.1 +)% +Drilling and completion fluids direct operating costs +$ +74,180 +$ +126,900 +(41.5 +)% +Drilling and completion fluids selling, general and +administrative +$ +7,192 +$ +10,110 +(28.9 +)% +Drilling and completion fluids depreciation +$ +2,287 +$ +2,830 +(29.2 +)% +Goodwill impairment +$ +— +$ +9,964 +(100.0 +)% +Impairment of assets held for sale +$ +1,900 +$ +— +N/A +% +Net gain on asset disposals/retirements +$ +(125 +) +$ +(155 +) +(19.4 +)% +Other operating expense +$ +890 +$ +— +N/A +% +Net interest expense +$ +— +$ +7 +(100.0 +)% +Income tax expense (benefit) +$ +(2,208 +) +$ +2,389 +N/A +% +Loss from discontinued operations, net of income taxes +$ +(4,330 +) +$ +(6,799 +) +36.3 +% +On January 20, 2010, we exited our drilling and completion +fluids services business which had previously been presented as +one of our reportable operating segments. On that date, our +wholly owned subsidiary, Ambar Lone Star Fluids Services LLC, +completed the sale of substantially all of its assets, excluding +billed accounts receivable. Upon our exit from this business, we +classified our drilling and completion fluids operating segment +as a discontinued operation. Accordingly, the assets and +liabilities of this business, along with its results of +operations, have been reclassified for all periods presented. +Drilling and completion fluids revenue and direct operating +costs decreased in 2009 due to decreased sales volume both on +land and offshore in the Gulf of Mexico. Drilling and completion +fluids selling, general and administrative expenses decreased in +2009 primarily due to a decrease in compensation costs for sales +and support personnel due to headcount reductions. Goodwill +impairment was recognized in the drilling and completion fluids +reporting unit in 2008 as a result of our annual impairment +testing which indicated that the fair value of goodwill in that +reporting unit was zero. Impairment of assets held for sale in +2009 of $1.9 million represents the adjustment recorded to +reduce the carrying value of the assets sold to their fair value +less transaction +26 +Table of Contents +costs as of December 31, 2009. In 2008, income tax expense +was recognized despite a pre-tax loss in the drilling and +completion fluids business due to the fact that the goodwill +impairment recorded in that year was not deductible for tax +purposes. +Comparison +of the years ended December 31, 2008 and 2007 +The following tables summarize operations by business segment +for the years ended December 31, 2008 and 2007: +Year Ended December 31, +Contract Drilling +2008 +2007 +% Change +(Dollars in thousands) +Revenues +$ +1,804,026 +$ +1,741,647 +3.6 +% +Direct operating costs +$ +1,038,327 +$ +963,150 +7.8 +% +Selling, general and administrative +$ +5,363 +$ +5,893 +(9.0 +)% +Depreciation and impairment +$ +239,700 +$ +213,812 +12.1 +% +Operating income +$ +520,636 +$ +558,792 +(6.8 +)% +Operating days +93,068 +89,095 +4.5 +% +Average revenue per operating day +$ +19.38 +$ +19.55 +(0.9 +)% +Average direct operating costs per operating day +$ +11.16 +$ +10.81 +3.2 +% +Average rigs operating +254 +244 +4.1 +% +Capital expenditures +$ +360,645 +$ +539,506 +(33.2 +)% +The demand for our contract drilling services is impacted by the +market price of natural gas and, to a lesser extent, oil. The +reactivation and construction of new land drilling rigs in the +United States in recent years has also contributed to an excess +capacity of land drilling rigs compared to demand. The average +market price of natural gas for each of the fiscal quarters and +full years in 2008 and 2007 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2007: +Average natural gas price(1) +$ +7.44 +$ +7.76 +$ +6.35 +$ +7.19 +$ +7.18 +2008: +Average natural gas price(1) +$ +8.92 +$ +11.74 +$ +9.28 +$ +6.60 +$ +9.13 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +Revenues and direct operating costs increased in 2008 compared +to 2007 primarily as a result of an increase in the number of +operating days. The increase in operating days was due to +increased demand caused by higher prices for natural gas during +most of 2008 compared to 2007. Average revenue per operating day +in 2008 was relatively flat compared to 2007. Average direct +operating costs per operating day increased in 2008 due to +incremental costs incurred to activate idle drilling rigs as +well as increases in labor, repairs and other related costs. +Significant capital expenditures were incurred in 2008 and 2007 +to build new drilling rigs, to modify and upgrade our drilling +rigs and to acquire additional related equipment such as drill +pipe, drill collars, engines, fluid circulating systems, rig +hoisting systems and safety enhancement equipment. Depreciation +and impairment expense in 2008 includes approximately +$10.4 million related to the impairment of drilling +equipment primarily related to drilling rigs +27 +Table of Contents +thatwere removed from our marketable fleet. We removed 22 rigs +from our marketable fleet in 2008. Depreciation expense +increased as a result of capital expenditures. +Year Ended December 31, +Pressure Pumping +2008 +2007 +% Change +(Dollars in thousands) +Revenues +$ +217,494 +$ +202,812 +7.2 +% +Direct operating costs +$ +132,570 +$ +105,273 +25.9 +% +Selling, general and administrative +$ +23,305 +$ +18,971 +22.8 +% +Depreciation +$ +19,600 +$ +14,311 +37.0 +% +Operating income +$ +42,019 +$ +64,257 +(34.6 +)% +Total jobs +12,900 +14,094 +(8.5 +)% +Average revenue per job +$ +16.86 +$ +14.39 +17.2 +% +Average direct operating costs per job +$ +10.28 +$ +7.47 +37.6 +% +Capital expenditures +$ +61,289 +$ +47,582 +28.8 +% +Our customers increased their focus on the emerging development +of unconventional reservoirs in the Appalachian Basin and the +larger jobs associated therewith. As a result of this focus on +unconventional reservoirs, we experienced a decrease in smaller +traditional pressure pumping jobs in 2008, which resulted in an +overall decrease in the number of total jobs. Revenues and +direct operating costs increased as a result of an increase in +the average revenue and average direct operating costs per job. +Increased average revenue per job was due to an increase in the +proportion of larger jobs to total jobs, which was driven by +demand for services associated with unconventional reservoirs. +Average direct operating costs per job increased due to the +increase in larger jobs and as a result of increases in +compensation, maintenance and the cost of materials used in our +operations. In anticipation of increased activity associated +with the unconventional reservoirs in the Appalachian Basin, we +added facilities, equipment and personnel. Delays in the +development of these reservoirs caused a slower increase in +customer activity than we had expected, negatively impacting the +profitability of this business. Selling, general and +administrative expense increased primarily as a result of +expenses to support expanded operations of this segment. +Significant capital expenditures were incurred to add capacity, +expand our areas of operation and modify and upgrade existing +equipment. Depreciation expense increased as a result of capital +expenditures. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2008 +2007 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +42,360 +$ +41,637 +1.7 +% +Direct operating costs +$ +12,793 +$ +10,864 +17.8 +% +Selling, general and administrative +$ +— +$ +2,365 +(100.0 +)% +Depreciation, depletion and impairment +$ +15,856 +$ +17,410 +(8.9 +)% +Operating income +$ +13,711 +$ +10,998 +24.7 +% +Capital expenditures +$ +22,981 +$ +17,516 +31.2 +% +Average net daily oil production (Bbls) +801 +971 +(17.5 +)% +Average net daily gas production (Mcf) +3,755 +4,996 +(24.8 +)% +Average oil sales price (per Bbl) +$ +98.70 +$ +68.82 +43.4 +% +Average gas sales price (per Mcf) +$ +9.77 +$ +7.37 +32.6 +% +Revenues increased due to higher average sales prices of oil and +natural gas. This increase was partially offset by a decrease in +the average net daily production of oil and natural gas and by +the elimination of well operations revenue due to the fourth +quarter 2007 sale of the operating responsibilities associated +with oil and natural gas wells. Average net daily oil and +natural gas production decreased primarily due to the sale of +properties in 2007 and production declines. Direct operating +costs increased due to an increase in seismic expenses as well +as increased production taxes and other production costs. +Selling, general and administrative expense decreased in 2008 +due to the sale of the operating responsibilities mentioned +above and the resulting elimination of headcount in this +28 +Table of Contents +segment. Depreciation, depletion and impairment expense in 2008 +includes approximately $4.4 million incurred to impair +certain oil and natural gas properties compared to approximately +$3.9 million incurred to impair certain oil and natural gas +properties in 2007. Depletion expense decreased approximately +$1.9 million primarily due to the sale of certain +properties in 2007. +Year Ended December 31, +Corporate and Other +2008 +2007 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +29,412 +$ +27,436 +7.2 +% +Depreciation +$ +834 +$ +813 +2.6 +% +Other operating expenses +$ +4,350 +$ +2,875 +51.3 +% +Embezzlement recoveries +$ +— +$ +(43,955 +) +(100.0 +)% +Net gain on asset disposals +$ +(4,163 +) +$ +(16,432 +) +(74.7 +)% +Interest income +$ +1,553 +$ +2,351 +(33.9 +)% +Interest expense +$ +630 +$ +2,187 +(71.2 +)% +Other income +$ +502 +$ +363 +38.3 +% +Capital expenditures +$ +511 +$ +— +N/A +% +Selling, general and administrative expense increased primarily +as a result of additional compensation expense and an increase +in payroll tax expense associated with the exercise of stock +options during 2008. Other operating expenses increased due to +an increase in bad debt expense. Gains and losses on the +disposal of assets are considered as part of our corporate +activities because such transactions relate to corporate +strategy decisions of our executive management group. Gains on +asset disposals in 2008 were primarily related to gains on the +sale of contract drilling equipment and the sale of oil and +natural gas properties. Gains on asset disposals in 2007 were +primarily related to the sale of oil and natural gas properties. +In November 2005, we discovered that our former Chief Financial +Officer, Jonathan D. Nelson (“Nelson”), had +fraudulently diverted approximately $77.5 million in +Company funds for his own benefit during the period from 1998 +through 2005. As a result, the Audit Committee of the Board of +Directors commenced an investigation into Nelson’s +activities and retained independent counsel and independent +forensic accountants to assist with the investigation. Nelson +has been sentenced and is serving a term of imprisonment arising +out of his embezzlement. A receiver was appointed to take +control of and liquidate the assets of Nelson. In May 2007, the +court approved a plan of distribution for the assets recovered +by the receiver. We recovered a total of approximately +$44.5 million pursuant to the approved plan, and we +recognized this recovery in our consolidated statement of income +in 2007, net of professional fees incurred as a result of the +embezzlement. +Year Ended December 31, +Discontinued Operations: +2008 +2007 +% Change +(Dollars in thousands) +Drilling and completion fluids revenue +$ +145,246 +$ +128,098 +13.4 +% +Drilling and completion fluids direct operating costs +$ +126,900 +$ +108,752 +16.7 +% +Drilling and completion fluids selling, general and +administrative +$ +10,110 +$ +9,958 +1.5 +% +Drilling and completion fluids depreciation +$ +2,830 +$ +2,860 +(1.0 +)% +Goodwill impairment +$ +9,964 +$ +— +N/A +% +Net gain on asset disposals/retirements +$ +(155 +) +$ +(113 +) +37.2 +% +Other operating benefit +$ +— +$ +(325 +) +(100.0 +)% +Net interest expense (income) +$ +7 +$ +(4 +) +N/A +% +Income tax expense +$ +2,389 +$ +2,818 +(15.2 +)% +Income (loss) from discontinued operations, net of income taxes +$ +(6,799 +) +$ +4,152 +N/A +% +29 +Table of Contents +Drilling and completion fluids revenue and direct operating +costs increased in 2008 due to increased sales volume both on +land and offshore in the Gulf of Mexico. Goodwill impairment was +recognized in the drilling and completion fluids reporting unit +in 2008 as a result of our annual impairment testing which +indicated that the fair value of goodwill in that reporting unit +was zero. No impairment of goodwill was recognized in 2007 as +the annual impairment testing did not indicate that an +impairment existed at that time. In 2008, income tax expense was +recognized despite a pre-tax loss in the drilling and completion +fluids business due to the fact that the goodwill impairment +recorded in that year was not deductible for tax purposes. +Income +Taxes +Year Ended December 31, +2009 +2008 +2007 +(Dollars in thousands) +Income (loss) from continuing operations before income tax +$ +(51,555 +) +$ +547,358 +$ +663,837 +Income tax expense (benefit) +(17,595 +) +193,490 +229,350 +Effective tax rate +34.1 +% +35.3 +% +34.5 +% +The effective tax rate is a result of a Federal rate of 35.0% +adjusted as follows: +2009 +2008 +2007 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +4.7 +1.7 +1.4 +Permanent differences +(5.7 +) +(1.2 +) +(1.6 +) +Other, net +0.1 +(0.2 +) +(0.3 +) +Effective tax rate +34.1 +% +35.3 +% +34.5 +% +The permanent differences indicated above are largely +attributable to our Domestic Production Activities deduction. +The Domestic Production Activities Deduction was enacted as part +of the American Jobs Creation Act of 2004 (as revised by the +Emergency Economic Stabilization Act of 2008, the +“Act”) and is effective for taxable years after +December 31, 2004. The Act allows a deduction of 6% on the +lesser of qualified production activities income or taxable +income. +We record deferred Federal income taxes based primarily on the +temporary differences between the book and tax bases of our +assets. Deferred tax assets and liabilities are measured using +enacted tax rates expected to apply to taxable income in the +year in which those temporary differences are expected to be +settled. As a result of fully recognizing the benefit of our +deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We recognized deferred tax expense +of approximately $101 million in 2009, $65.4 million +in 2008 and $38.3 million in 2007. +Volatility +of Oil and Natural Gas Prices and its Impact on Operations and +Financial Condition +Our revenue, profitability, financial condition and rate of +growth are substantially dependent upon prevailing prices for +natural gas and, to a lesser extent, oil. For many years, oil +and natural gas prices and markets have been extremely volatile. +Prices are affected by market supply and demand factors as well +as international military, political and economic conditions, +and the ability of OPEC to set and maintain production and price +targets. All of these factors are beyond our control. During +2008, the monthly average market price of natural gas (monthly +average Henry Hub price as reported by the Energy Information +Administration) peaked in June at $13.06 per Mcf before rapidly +declining to an average of $5.99 per Mcf in December. In 2009, +the monthly average market price of natural gas declined further +to a low of $3.06 per Mcf in September. This decline in the +market price of natural gas resulted in our customers +significantly reducing their drilling activities beginning in +the fourth quarter of 2008 and drilling activities remained low +throughout 2009. This reduction in demand combined with the +reactivation and construction of new land drilling rigs in the +United States during the last several years has resulted in +excess capacity compared to demand. As a result of these +factors, our average number of rigs operating has declined +significantly. We expect oil and natural gas prices to continue +to be volatile and to affect our financial condition, +30 +Table of Contents +operations and ability to access sources of capital. Low market +prices for natural gas would likely result in demand for our +drilling rigs remaining low and adversely affect our operating +results, financial condition and cash flows. +The North American land drilling industry has experienced +downturns in demand during the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins and, +at times, have incurred losses during the downturn periods. +Impact of +Inflation +Inflation has not had a significant impact on our operations +during the three years in the period ended December 31, +2009. We believe that inflation will not have a significant +near-term impact on our financial position. +Recently +Issued Accounting Standards +In June 2008, the FASB issued a new accounting standard which +clarifies that share-based payment awards that entitle their +holders to receive non-forfeitable dividends before vesting +should be considered participating securities and, as such, +should be included in the calculation of basic +earnings-per-share +using the two-class method. Certain of our share-based payment +awards entitle the holders to receive non-forfeitable dividends. +This standard is effective for financial statements issued for +fiscal years beginning after December 15, 2008, as well as +interim periods within those years and became effective for us +on January 1, 2009. The impact of the adoption of this +standard is discussed in Note 1 of our Consolidated +Financial Statements. +In December 2008, the SEC issued a Final Rule, Modernization +of Oil and Gas Reporting (“Final Rule”). The Final +Rule revises certain oil and gas reporting disclosures in +Regulation S-K +and +Regulation S-X +under the Securities Act, and the Exchange Act, as well as +Industry Guide 2. The amendments are designed to modernize and +update oil and gas disclosure requirements to align them with +current practices and changes in technology. The disclosure +requirements are effective for registration statements filed on +or after January 1, 2010 and for annual financial +statements filed on or after December 31, 2009. We applied +the provisions of the Final Rule in connection with our +December 31, 2009 oil and natural gas reserve estimation +process. The application of the Final Rule did not have a +material impact on us. +In April 2009, the FASB issued a staff position to provide +additional guidance for determining whether a market for a +financial asset is not active and a transaction is not +distressed for fair value measurements under generally accepted +accounting principles. The provisions of this staff position are +effective for financial statements issued for interim and annual +periods ending after June 15, 2009 and became effective for +us in the quarter ended June 30, 2009. The adoption of this +staff position did not have a material impact on us. +In April 2009, the FASB issued a staff position which increases +the frequency of fair value disclosures for financial +instruments from annual only to quarterly reporting periods. The +provisions of this staff position are effective for financial +statements issued for interim and annual periods ending after +June 15, 2009 and became effective for us in the quarter +ended June 30, 2009. The adoption of this staff position +did not have a material impact on us. +In June 2009, the FASB issued a new accounting standard that +amends the accounting and disclosure requirements for the +consolidation of variable interest entities. This new standard +removes the previously existing exception from applying +consolidation guidance to qualifying special-purpose entities +and requires ongoing reassessments of whether an enterprise is +the primary beneficiary of a variable interest entity. Before +this new standard, generally accepted accounting principles +required reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for us on January 1, 2010. The +adoption of this standard did not impact our consolidated +financial statements. +In June 2009, the FASB issued the FASB Accounting Standards +Codification (“Codification”). Effective for financial +statements issued for interim and annual periods ending after +September 15, 2009, the Codification +31 +Table of Contents +became the source of authoritative U.S. generally accepted +accounting principles. The FASB will no longer issue new +standards in the form of Statements, FASB Staff Positions or +EITF Abstracts. Instead, it will issue Accounting Standards +Updates to update the Codification. The adoption of the +Codification did not impact our consolidated financial +statements. +Item 7A. +Quantitative +and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk +associated with any borrowings that we have under our revolving +credit facility. The revolving credit facility calls for +periodic interest payments at a floating rate ranging from LIBOR +plus 3.00% to 4.00% or at the prime rate. The applicable rate +above LIBOR is based upon our debt to capitalization ratio. As +of December 31, 2009, we had no borrowings outstanding +under our revolving credit facility. +We conduct a portion of our business in Canadian dollars through +our Canadian land-based drilling operations. The exchange rate +between Canadian dollars and U.S. dollars has fluctuated +during the last several years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and +earnings of our Canadian operations will be reduced and the +value of our Canadian net assets will decline when they are +translated to U.S. dollars. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +Item 8. +Financial +Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the +end of Part IV hereof beginning at +page F-1, +Index to Consolidated Financial Statements, and are incorporated +herein by this reference. +Item 9. +Changes +in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined in +Rules 13a-15(e) +and +15d-15(e) +promulgated under the Exchange Act, as of the end of the period +covered by this Report. Based on this evaluation, our CEO and +CFO concluded that, as of December 31, 2009, our disclosure +controls and procedures were effective to ensure that +information required to be disclosed by us in reports that we +file or submit under the Exchange Act is recorded, processed, +summarized and reported within the time periods specified in SEC +rules and forms and is accumulated and reported to our +management, including our CEO and CFO, as appropriate to allow +timely decisions regarding required disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2009, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2009. +The effectiveness of our internal control over financial +reporting as of December 31, 2009 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and is incorporated by reference into Item 8 +of this Report. +32 +Table of Contents +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. +Item 9B. +Other +Information +None. +33 +Table of Contents +PART III +The information required by Part III is omitted from this +Report because we expect to file a definitive proxy statement +(the “Proxy Statement”) pursuant to +Regulation 14A of the Securities Exchange Act of 1934 no +later than 120 days after the end of the fiscal year +covered by this Report and certain information included therein +is incorporated herein by reference. +Item 10. +Directors, +Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +We have adopted a Code of Business Conduct and Ethics for Senior +Financial Executives, which covers, among others, our principal +executive officer, principal financial officer and principal +accounting officer. The text of this code is located on our +website under “Governance.” Our Internet address is +www.patenergy.com. We intend to disclose any amendments to or +waivers from this code on our website. +Item 11. +Executive +Compensation. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 12. +Security +Ownership of Certain Beneficial Owners and Management and +Related Stockholder Matters. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +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. +34 +Table of Contents +PART IV +Item 15. +Exhibits +and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 +of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts +is filed herewith on +page S-1. +All other financial statement schedules have been omitted +because they are not applicable or the information required +therein is included elsewhere in the financial statements or +notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by +reference herein. +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.6 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +35 +Table of Contents +10 +.8 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.9 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time.* +10 +.10 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.11 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.12 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.13 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.14 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.15 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.16 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.19 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.20 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.21 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +36 +Table of Contents +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +Credit Agreement dated March 20, 2009, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer, swing line lender +and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC +Bank USA, N.A., as lender, Bank of America, N.A., as syndication +agent, letter of credit issuer and lender, and The Bank of +Tokyo-Mitsubishi UFJ, Ltd. as documentation agent and lender +(filed March 25, 2009 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.24 +Commitment Increase and Joinder Agreement dated June 19, +2009, among the Company, as borrower, Regions Bank as the new +lender, Bank of America, N.A., as a letter of credit issuer and +Wells Fargo Bank, N.A., as administrative agent, letter of +credit issuer, swing line lender and lender (filed +August 4, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on Form +10-Q and +incorporated herein by reference). +10 +.25 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2009, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Operations, (iii) the Consolidated Statements +of Changes in Stockholders’ Equity, (iv) the +Consolidated Statements of Cash Flows, (v) Notes to +Consolidated Financial Statements, tagged as blocks of text, and +(vi) Valuation and Qualifying Accounts. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. +37 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of Independent Registered Public +Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of +December 31, 2009 and 2008 +F-3 +Consolidated Statements of Operations for the +years ended December 31, 2009, 2008 and 2007 +F-4 +Consolidated Statements of Changes In +Stockholders’ Equity for the years ended December 31, +2009, 2008 and 2007 +F-5 +Consolidated Statements of Cash Flows for the +years ended December 31, 2009, 2008 and 2007 +F-6 +Notes to Consolidated Financial Statements +F-7 +Financial Statement Schedule +S-1 +EX-10.9 +EX-21.1 +EX-23.1 +EX-31.1 +EX-31.2 +EX-32.1 +EX-101 INSTANCE DOCUMENT +EX-101 SCHEMA DOCUMENT +EX-101 CALCULATION LINKBASE DOCUMENT +EX-101 LABELS LINKBASE DOCUMENT +EX-101 PRESENTATION LINKBASE DOCUMENT +EX-101 DEFINITION LINKBASE DOCUMENT +F-1 +Table of Contents +Report of +Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders +of Patterson-UTI Energy, Inc.: +In our opinion, the consolidated financial statements listed in +the accompanying index present fairly, in all material respects, +the financial position of Patterson-UTI Energy, Inc. and its +subsidiaries (the “Company”) at December 31, 2009 +and 2008, and the results of their operations and their cash +flows for each of the three years in the period ended +December 31, 2009 in conformity with accounting principles +generally accepted in the United States of America. In addition, +in our opinion, the financial 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 financial +statements. Also in our opinion, the Company maintained, in all +material respects, effective internal control over financial +reporting as of December 31, 2009, based on criteria +established in Internal Control — Integrated +Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). The +Company’s management is responsible for these financial +statements and financial statement schedule, for maintaining +effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over +financial reporting, included in Management’s Report on +Internal Control over Financial Reporting appearing under +Item 9A. Our responsibility is to express opinions on these +financial statements, on the financial statement schedule, and +on the Company’s internal control over financial reporting +based on our integrated audits. We conducted our audits in +accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we +plan and perform the audits to obtain reasonable assurance about +whether the financial statements are free of material +misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test +basis, evidence supporting the amounts and disclosures in the +financial statements, assessing the accounting principles used +and significant estimates made by management, and evaluating the +overall financial statement presentation. Our audit of internal +control over financial reporting included obtaining an +understanding of internal control over financial reporting, +assessing the risk that a material weakness exists, and testing +and evaluating the design and operating effectiveness of +internal control based on the assessed risk. Our audits also +included performing such other procedures as we considered +necessary in the circumstances. We believe that our audits +provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 19, 2010 +F-2 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2009 +2008 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +49,877 +$ +81,223 +Accounts receivable, net of allowance for doubtful accounts of +$10,911 and $9,330 at December 31, 2009 and 2008, +respectively +164,498 +414,531 +Federal and state income taxes receivable +118,869 +10,175 +Inventory +6,941 +41,999 +Deferred tax assets, net +32,877 +35,928 +Assets held for sale +42,424 +— +Other +41,782 +57,518 +Total current assets +457,268 +641,374 +Property and equipment, net +2,110,402 +1,937,112 +Goodwill +86,234 +86,234 +Deposits on equipment purchases +914 +43,944 +Other +7,334 +4,153 +Total assets +$ +2,662,152 +$ +2,712,817 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +83,700 +$ +169,958 +Accrued expenses +109,608 +132,655 +Total current liabilities +193,308 +302,613 +Borrowings under revolving credit facility +— +— +Deferred tax liabilities, net +381,656 +277,717 +Other +5,488 +5,545 +Total liabilities +580,452 +585,875 +Commitments and contingencies (see Note 9) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 180,828,773 and 180,192,093 issued and 153,610,785 and +153,094,803 outstanding at December 31, 2009 and 2008, +respectively +1,808 +1,801 +Additional paid-in capital +781,635 +765,512 +Retained earnings +1,901,853 +1,970,824 +Accumulated other comprehensive income +14,996 +5,774 +Treasury stock, at cost, 27,217,988 shares and +27,097,290 shares at December 31, 2009 and 2008, +respectively +(618,592 +) +(616,969 +) +Total stockholders’ equity +2,081,700 +2,126,942 +Total liabilities and stockholders’ equity +$ +2,662,152 +$ +2,712,817 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +Year Ended December 31, +2009 +2008 +2007 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +599,287 +$ +1,804,026 +$ +1,741,647 +Pressure pumping +161,441 +217,494 +202,812 +Oil and natural gas +21,218 +42,360 +41,637 +Total operating revenues +781,946 +2,063,880 +1,986,096 +Operating costs and expenses: +Contract drilling +357,742 +1,038,327 +963,150 +Pressure pumping +111,414 +132,570 +105,273 +Oil and natural gas +7,341 +12,793 +10,864 +Depreciation, depletion and impairment +289,847 +275,990 +246,346 +Selling, general and administrative +56,621 +58,080 +54,665 +Embezzlement recoveries +— +— +(43,955 +) +Net loss (gain) on asset disposals +3,385 +(4,163 +) +(16,432 +) +Other operating expenses +3,810 +4,350 +2,875 +Total operating costs and expenses +830,160 +1,517,947 +1,322,786 +Operating income (loss) +(48,214 +) +545,933 +663,310 +Other income (expense): +Interest income +381 +1,553 +2,351 +Interest expense +(4,148 +) +(630 +) +(2,187 +) +Other +426 +502 +363 +Total other income (expense) +(3,341 +) +1,425 +527 +Income (loss) before income taxes +(51,555 +) +547,358 +663,837 +Income tax expense (benefit): +Current +(119,038 +) +128,098 +191,028 +Deferred +101,443 +65,392 +38,322 +Total income tax expense (benefit) +(17,595 +) +193,490 +229,350 +Income (loss) from continuing operations +(33,960 +) +353,868 +434,487 +Income (loss) from discontinued operations, net of income taxes +(4,330 +) +(6,799 +) +4,152 +Net income (loss) +$ +(38,290 +) +$ +347,069 +$ +438,639 +Basic income (loss) per common share: +Income (loss) from continuing operations +$ +(0.22 +) +$ +2.29 +$ +2.78 +Income (loss) from discontinued operations, net of income taxes +(0.03 +) +(0.04 +) +0.03 +Net income (loss) +$ +(0.25 +) +$ +2.25 +$ +2.81 +Diluted income (loss) per common share: +Income (loss) from continuing operations +$ +(0.22 +) +$ +2.27 +$ +2.75 +Income (loss) from discontinued operations, net of income taxes +(0.03 +) +(0.04 +) +0.03 +Net income (loss) +$ +(0.25 +) +$ +2.23 +$ +2.78 +Weighted average number of common shares outstanding: +Basic +152,069 +153,379 +154,755 +Diluted +152,069 +154,358 +156,612 +Cash dividends per common share +$ +0.20 +$ +0.60 +$ +0.44 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2006 +176,656 +$ +1,766 +$ +681,069 +$ +1,346,542 +$ +8,390 +$ +(475,301 +) +$ +1,562,466 +Comprehensive income: +Net income +— +— +— +438,639 +— +— +438,639 +Foreign currency translation adjustment, (net of tax of $6,755) +— +— +— +— +11,817 +— +11,817 +Total comprehensive income +— +— +— +438,639 +11,817 +— +450,456 +Issuance of restricted stock +601 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(101 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +230 +2 +2,048 +— +— +— +2,050 +Stock-based compensation +— +— +19,364 +— +— +— +19,364 +Tax benefit related to stock-based compensation +— +— +1,105 +— +— +— +1,105 +Payment of cash dividends +— +— +— +(68,561 +) +— +— +(68,561 +) +Purchase of treasury stock +— +— +— +— +— +(70,850 +) +(70,850 +) +Balance, December 31, 2007 +177,386 +1,773 +703,581 +1,716,620 +20,207 +(546,151 +) +1,896,030 +Comprehensive income: +Net income +— +— +— +347,069 +— +— +347,069 +Foreign currency translation adjustment, (net of tax of $8,368) +— +— +— +— +(14,433 +) +— +(14,433 +) +Total comprehensive income +— +— +— +347,069 +(14,433 +) +— +332,636 +Issuance of restricted stock +577 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(75 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +2,304 +23 +25,525 +— +— +— +25,548 +Stock-based compensation +— +— +20,131 +— +— +— +20,131 +Tax benefit related to stock-based compensation +— +— +16,280 +— +— +— +16,280 +Payment of cash dividends +— +— +— +(92,865 +) +— +— +(92,865 +) +Purchase of treasury stock +— +— +— +— +— +(70,818 +) +(70,818 +) +Balance, December 31, 2008 +180,192 +1,801 +765,512 +1,970,824 +5,774 +(616,969 +) +2,126,942 +Comprehensive income (loss): +Net loss +— +— +— +(38,290 +) +— +— +(38,290 +) +Foreign currency translation adjustment, (net of tax of $5,347) +— +— +— +— +9,222 +— +9,222 +Total comprehensive loss +— +— +— +(38,290 +) +9,222 +— +(29,068 +) +Issuance of restricted stock +604 +6 +(6 +) +— +— +— +— +Vesting of restricted stock units +6 +— +— +— +— +— +— +Forfeitures of restricted stock +(56 +) +— +— +— +— +— +— +Exercise of stock options +83 +1 +568 +— +— +— +569 +Stock-based compensation +— +— +18,565 +— +— +— +18,565 +Tax expense related to stock-based compensation +— +— +(3,004 +) +— +— +— +(3,004 +) +Payment of cash dividends +— +— +— +(30,681 +) +— +— +(30,681 +) +Purchase of treasury stock +— +— +— +— +— +(1,623 +) +(1,623 +) +Balance, December 31, 2009 +180,829 +$ +1,808 +$ +781,635 +$ +1,901,853 +$ +14,996 +$ +(618,592 +) +$ +2,081,700 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Year Ended December 31, +2009 +2008 +2007 +(In thousands) +Cash flows from operating activities: +Net income (loss) +$ +(38,290 +) +$ +347,069 +$ +438,639 +Adjustments to reconcile net income (loss) to net cash provided +by operating activities: +Depreciation, depletion and impairment +289,847 +275,990 +246,346 +Provision for bad debts +3,810 +4,350 +2,875 +Dry holes and abandonments +129 +1,617 +1,309 +Deferred income tax expense +101,443 +65,392 +38,322 +Stock-based compensation expense +18,214 +19,688 +18,873 +Net loss (gain) on asset disposals +3,385 +(4,163 +) +(16,432 +) +Tax expense related to stock-based compensation +(3,004 +) +— +— +Changes in operating assets and liabilities: +Accounts receivable +213,813 +(30,777 +) +100,429 +Income taxes receivable/payable +(108,664 +) +(11,258 +) +7,174 +Inventory and other assets +14,178 +2,498 +2,211 +Accounts payable +(52,673 +) +6,486 +(37,412 +) +Accrued expenses +(21,178 +) +(4,474 +) +(5,640 +) +Other liabilities +(92 +) +1,242 +1,434 +Net cash provided by operating activities of discontinued +operations +32,759 +1,344 +14,096 +Net cash provided by operating activities +453,677 +675,004 +812,224 +Cash flows from investing activities: +Acquisitions +— +— +(29,000 +) +Purchases of property and equipment +(452,646 +) +(445,426 +) +(604,604 +) +Proceeds from disposal of assets +3,359 +11,436 +34,054 +Net cash used in investing activities of discontinued operations +(54 +) +(3,286 +) +(2,912 +) +Net cash used in investing activities +(449,341 +) +(437,276 +) +(602,462 +) +Cash flows from financing activities: +Purchases of treasury stock +(1,623 +) +(70,818 +) +(70,850 +) +Dividends paid +(30,681 +) +(92,865 +) +(68,561 +) +Tax benefit related to stock-based compensation +— +16,280 +1,105 +Proceeds from borrowings under revolving credit facility +— +— +142,500 +Repayment of borrowings under revolving credit facility +— +(50,000 +) +(212,500 +) +Revolving credit facility issuance costs +(6,169 +) +— +— +Proceeds from exercise of stock options +569 +25,548 +2,050 +Net cash used in financing activities +(37,904 +) +(171,855 +) +(206,256 +) +Effect of foreign exchange rate changes on cash +2,222 +(2,084 +) +543 +Net increase (decrease) in cash and cash equivalents +(31,346 +) +63,789 +4,049 +Cash and cash equivalents at beginning of year +81,223 +17,434 +13,385 +Cash and cash equivalents at end of year +$ +49,877 +$ +81,223 +$ +17,434 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest expense +$ +(1,804 +) +$ +(323 +) +$ +(1,808 +) +Income taxes +14,029 +(126,331 +) +(176,281 +) +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property +and equipment +$ +(25,110 +) +$ +(3,590 +) +$ +597 +Net (increase) decrease in deposits on equipment purchases +43,029 +(42,293 +) +23,095 +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., through 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, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +Pennsylvania, West Virginia and western Canada. The Company +provides pressure pumping services primarily in the Appalachian +Basin. The Company also owns and invests in oil and natural gas +assets as a working interest owner primarily in Texas and New +Mexico. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. Except for +wholly-owned subsidiaries, the Company has no controlling +financial interests in any entity which would require +consolidation. +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 its functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting. The Company +follows the +percentage-of-completion +method of accounting for footage contract drilling arrangements. +Under the +percentage-of-completion +method, management estimates are relied upon in the +determination of the total estimated expenses to be incurred +drilling the well. Due to the nature of turnkey contract +drilling arrangements and risks therein, the Company follows the +completed contract method of accounting for such arrangements. +Under this method, all drilling 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. Except for two wells drilled under +footage contracts in 2009, all of the wells the Company drilled +during the years ended December 31, 2009, 2008 and 2007 +were under daywork contracts. +Accounts receivable — Trade accounts receivable +are recorded at the invoiced amount. 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 at least quarterly. Significant individual +accounts receivable balances and balances which have been +outstanding greater than 90 days are reviewed individually +for collectibility. Account balances, when determined to be +uncollectible, are charged against the allowance. +Inventories — Inventories at December 31, +2009 consist primarily of chemical products and sand to be used +in conjunction with the Company’s pressure pumping +activities. Inventories at December 31, 2008 consisted +primarily of chemical products to be used in conjunction with +the Company’s drilling and completion fluids activities. +The inventories are stated at the lower of cost or market, +determined by the +first-in, +first-out method. +F-7 +Table of Contents +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change when +equipment becomes idle. The estimated useful lives, in years, +are shown below: +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are +evaluated for impairment when certain triggering events or +changes in circumstances indicate that the carrying values may +not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and the economic operating viability +of the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project after one year following the completion of drilling, the +Company considers the costs of the well to be impaired and +recognizes the costs as expense. Geological and geophysical +costs, including seismic costs, and costs to carry and retain +undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful +exploratory type wells, consisting of lease and well equipment, +lease acquisition costs and intangible development costs, are +depreciated, depleted and amortized on the +units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves of each respective field. +The Company reviews its proved oil and natural gas properties +for impairment when a triggering event occurs such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on +management’s expectation of future pricing over the lives +of the respective fields. These estimates are then reviewed by +an independent petroleum engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment +expense is measured and recognized as the difference between its +net book value and discounted cash flow. Unproved oil and +natural gas properties are reviewed quarterly to assess +potential 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 — Goodwill is considered to have an +indefinite useful economic life and is not amortized. The +Company assesses impairment of its goodwill at least annually or +on an interim basis if triggering events or circumstances +indicate that the fair value of the asset may have decreased +below its carrying value. As discussed in Note 5, the +Company determined that goodwill in its drilling and completion +fluids reporting unit was impaired in connection with its annual +impairment testing performed as of December 31, 2008. As +discussed in Note 2, the Company exited the drilling and +completion fluids business in January 2010, and this impairment +charge is included in the results of discontinued operations in +the consolidated statements of operations for the year ended +December 31, 2008. +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Disposals — Upon disposition of property and +equipment, the cost and related accumulated depreciation are +removed and any resulting gain or loss is reflected in the +consolidated statement of operations. +Net income (loss) per common share — The +Company provides a dual presentation of its net income (loss) +per common share in its consolidated statements of operations: +Basic net income (loss) per common share (“Basic EPS”) +and diluted net income (loss) per common share (“Diluted +EPS”). The Company adopted a new accounting standard on +January 1, 2009, which clarified that share-based payment +awards that entitle their holders to receive +F-8 +Table of Contents +non-forfeitable dividends before vesting should be considered +participating securities and, as such, should be included in the +calculation of +earnings-per-share +using the two-class method. All +earnings-per-share +data presented for the years ended December 31, 2008 and +2007 have been adjusted retrospectively to conform with this +accounting standard. The impact of this retrospective +application to the year ended December 31, 2008 was to +reduce Basic and Diluted EPS by $0.01. The impact of this +retrospective application to the year ended December 31, +2007 was to reduce Basic EPS by $0.02 and to reduce Diluted EPS +by $0.01. +Basic EPS excludes dilution and is computed by first allocating +earnings between common stockholders and holders of non-vested +shares of restricted stock. Basic EPS is then determined by +dividing the earnings attributable to common stockholders by the +weighted average number of common shares outstanding during the +period, excluding non-vested shares of restricted stock. +Diluted EPS is based on the weighted average number of common +shares outstanding plus the dilutive effect of potential common +shares, including stock options, non-vested shares of restricted +stock and restricted stock units. The dilutive effect of stock +options and restricted stock units is determined using the +treasury stock method. The dilutive effect of non-vested shares +of restricted stock is based on the more dilutive of the +treasury stock method or the two-class method, assuming a +reallocation of undistributed earnings to common stockholders +after considering the dilutive effect of potential common shares +other than non-vested shares of restricted stock. +The following table presents information necessary to calculate +income (loss) from continuing operations per share, income(loss) +from discontinued operations per share and net income (loss) per +share for the years ended December 31, 2009, 2008 and 2007 +as well as potentially dilutive securities excluded from the +weighted average number of diluted common shares outstanding, as +their inclusion would have been anti-dilutive (in thousands, +except per share amounts): +2009 +2008 +2007 +BASIC EPS: +Income (loss) from continuing operations +$ +(33,960 +) +$ +353,868 +$ +434,487 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +313 +(3,279 +) +(3,886 +) +Income (loss) from continuing operations attributed to common +stockholders +$ +(33,647 +) +$ +350,589 +$ +430,601 +Income (loss) from discontinued operations, net +$ +(4,330 +) +$ +(6,799 +) +$ +4,152 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +38 +64 +(37 +) +Income (loss) from discontinued operations attributed to common +stockholders +$ +(4,292 +) +$ +(6,735 +) +$ +4,115 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,069 +153,379 +154,755 +Basic income (loss) from continuing operations per common share +$ +(0.22 +) +$ +2.29 +$ +2.78 +Basic income (loss) from discontinued operations per common share +(0.03 +) +(0.04 +) +0.03 +Basic net income (loss) per common share +$ +(0.25 +) +$ +2.25 +$ +2.81 +F-9 +Table of Contents +2009 +2008 +2007 +DILUTED EPS: +Income (loss) from continuing operations attributed to common +stockholders +$ +(33,647 +) +$ +350,589 +$ +430,601 +Add incremental earnings related to potential common shares +— +15 +39 +Adjusted income (loss) from continuing operations attributed to +common stockholders +$ +(33,647 +) +$ +350,604 +$ +430,640 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,069 +153,379 +154,755 +Add dilutive effect of potential common shares +— +979 +1,857 +Weighted average number of diluted common shares outstanding +152,069 +154,358 +156,612 +Diluted income (loss) from continuing operations per common share +$ +(0.22 +) +$ +2.27 +$ +2.75 +Diluted income (loss) from discontinued operations per common +share +(0.03 +) +(0.04 +) +0.03 +Diluted net income (loss) per common share +$ +(0.25 +) +$ +2.23 +$ +2.78 +Potentially dilutive securities excluded as anti-dilutive +8,090 +2,455 +2,460 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. +The Company adopted a new accounting standard on January 1, +2007 which clarified the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribed a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of this standard in 2007, the Company +reduced a reserve for an uncertain tax position related to a +prior business combination that had originally been recorded as +goodwill in its contract drilling segment. The impact of this +adjustment was to reduce goodwill in the contract drilling +segment by approximately $2.9 million upon adoption of the +new standard. The impact of adjustments to reserves with respect +to other uncertain tax positions was not material. The +Company’s policy is to account for interest and penalties +with respect to income taxes as operating expenses. +Stock based compensation — The Company +recognizes the cost of share-based payments under the +fair-value-based method. Under this method, compensation cost +related to share-based payments is measured based on the +estimated fair value of the awards at the date of grant, net of +estimated forfeitures. This expense is recognized over the +expected life of the awards (See Note 11). +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Subsequent Events — The Company has performed +an evaluation of subsequent events through February 19, 2010 at +the time of issuance of the consolidated financial statements. +Recently Issued Accounting Standards — In June +2008, the FASB issued an accounting standard which clarifies +that share-based payment awards that entitle their holders to +receive non-forfeitable dividends before +F-10 +Table of Contents +vesting should be considered participating securities and, as +such, should be included in the calculation of basic +earnings-per-share +using the two-class method. Certain of the Company’s +share-based payment awards entitle the holders to receive +non-forfeitable dividends. This standard is effective for +financial statements issued for fiscal years beginning after +December 15, 2008, as well as interim periods within those +years, and became effective for the Company on January 1, +2009. The impact of the adoption of this standard is discussed +in this Note 1. +In December 2008, the SEC issued a Final Rule, Modernization +of Oil and Gas Reporting (“Final Rule”). The Final +Rule revises certain oil and gas reporting disclosures in +Regulation S-K +and +Regulation S-X +under the Securities Act, and the Exchange Act, as well as +Industry Guide 2. The amendments are designed to modernize and +update oil and gas disclosure requirements to align them with +current practices and changes in technology. The disclosure +requirements are effective for registration statements filed on +or after January 1, 2010 and for annual financial +statements filed on or after December 31, 2009. The Company +applied the provisions of the Final Rule in connection with its +December 31, 2009 oil and natural gas reserve estimation +process. The application of the Final Rule did not have a +material impact on the Company. +In April 2009, the FASB issued a staff position to provide +additional guidance for determining whether a market for a +financial asset is not active and a transaction is not +distressed for fair value measurements under generally accepted +accounting principles. The provisions of this staff position are +effective for financial statements issued for interim and annual +periods ending after June 15, 2009 and became effective for +the Company in the quarter ended June 30, 2009. The +adoption of this staff position did not have a material impact +on the Company. +In June 2009, the FASB issued a new accounting standard that +amends the accounting and disclosure requirements for the +consolidation of variable interest entities. This new standard +removes the previously existing exception from applying +consolidation guidance to qualifying special-purpose entities +and requires ongoing reassessments of whether an enterprise is +the primary beneficiary of a variable interest entity. Before +this new standard, generally accepted accounting principles +required reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for the Company on January 1, +2010. The adoption of this standard did not impact the +Company’s consolidated financial statements. +In June 2009, the FASB issued the FASB Accounting Standards +Codification (“Codification”). Effective for financial +statements issued for interim and annual periods ending after +September 15, 2009, the Codification became the source of +authoritative U.S. generally accepted accounting +principles. The FASB will no longer issue new standards in the +form of Statements, FASB Staff Positions or EITF Abstracts. +Instead, it will issue Accounting Standards Updates to update +the Codification. The adoption of the Codification did not +impact the Company’s consolidated financial statements. +Reclassifications — Certain reclassifications +have been made to the 2008 and 2007 consolidated financial +statements in order for them to conform with the 2009 +presentation. These reclassifications had no impact on the +Company’s financial position, results of operations or cash +flows. +2. +Discontinued +Operations +On January 20, 2010, the Company exited the drilling and +completion fluids services business, which had previously been +presented as one of the Company’s reportable operating +segments. On that date, the Company’s wholly owned +subsidiary, Ambar Lone Star Fluids Services LLC, completed the +sale of substantially all of its assets, excluding billed +accounts receivable. The sales price was approximately +$44.3 million, subject to any post-closing adjustments to +reflect the actual assets transferred as of the closing date. +Upon the Company’s exit from the drilling and completion +fluids services business, the Company classified its drilling +and completion fluids operating segment as a discontinued +operation. Accordingly, the results of operations of this +business have been reclassified and presented as results of +discontinued operations for all periods presented in these +consolidated financial statements. As of December 31, 2009, +the assets to be disposed of are considered held for sale and +are presented separately under the caption “Assets held for +sale” in the consolidated balance sheet. These assets are +included in the balance sheet at fair value less transaction +costs. The fair value of the assets to be disposed of was +estimated to be +F-11 +Table of Contents +approximately $44.3 million based on the expected sales +price described above. The source of this estimate was from a +third party and it is considered a level 2 input in the fair +value hierarchy of fair value accounting. Costs to sell the +disposal group were estimated to be $1.9 million. An impairment +charge of $1.9 million was recognized to reduce the carrying +value of the disposal group to its estimated fair value less +costs to sell. +Summarized operating results from discontinued operations for +the years ended December 31, 2009, 2008 and 2007 are shown +below (in thousands): +2009 +2008 +2007 +Drilling and completion fluids revenues +$ +79,786 +$ +145,246 +$ +128,098 +Income (loss) before income taxes +$ +(6,538 +) +$ +(4,410 +) +$ +6,970 +Income tax benefit (expense) +2,208 +(2,389 +) +(2,818 +) +Income (loss) from discontinued operations +$ +(4,330 +) +$ +(6,799 +) +$ +4,152 +The loss before income taxes in 2008 includes $9.96 million +in non-deductible charges resulting from the impairment of +goodwill. As a result, income tax expense was incurred for the +year despite the fact that the discontinued operation had a +pre-tax book loss. +The components of assets held for sale at December 31, 2009 +are shown below (in thousands): +Assets held for sale: +Inventory +$ +28,620 +Unbilled accounts receivable +6,587 +Prepaid expenses and other current assets +324 +Property and equipment, net +8,793 +Reserve to reduce disposal group to fair value less costs to sell +(1,900 +) +Total assets held for sale +$ +42,424 +3. +Acquisitions +On October 9, 2007, the Company acquired three recently +refurbished SCR electric land-based drilling rigs and spare +drilling equipment for $29.0 million. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2009 and 2008 (in thousands): +2009 +2008 +Equipment +$ +3,230,737 +$ +2,897,431 +Oil and natural gas properties +93,354 +89,809 +Buildings +56,563 +61,529 +Land +9,795 +10,196 +3,390,449 +3,058,965 +Less accumulated depreciation and depletion +(1,280,047 +) +(1,121,853 +) +Property and equipment, net +$ +2,110,402 +$ +1,937,112 +F-12 +Table of Contents +Depreciation, depletion and impairment — The +following table summarizes depreciation, depletion and +impairment expense related to property and equipment for 2009, +2008 and 2007 (in millions): +2009 +2008 +2007 +Depreciation and impairment expense +$ +280.6 +$ +264.5 +$ +232.9 +Depletion expense +9.2 +11.5 +13.4 +Total +$ +289.8 +$ +276.0 +$ +246.3 +The Company evaluates the recoverability of its long-lived +assets whenever events or changes in circumstances indicate that +their carrying amounts may not be recoverable. In light of +adverse market conditions affecting the Company beginning in the +fourth quarter of 2008 and continuing into 2009, including a +substantial decrease in the operating levels of certain of its +business segments, a significant decline in oil and natural gas +commodity prices, and the results of the Company’s annual +goodwill impairment test at December 31, 2008 (see +Note 5), the Company deemed it necessary to assess the +recoverability of long-lived assets within its contract drilling +and drilling and completion fluids segments in 2008. Due to a +continued decrease in the operating levels in its contract +drilling business segment through the first three quarters of +2009, the Company again deemed it necessary to assess the +recoverability of long-lived assets within that segment during +2009. With respect to the long-lived assets in the +Company’s oil and natural gas exploration and production +segment, the Company assesses the recoverability of long-lived +assets at the end of each quarter due to revisions in its oil +and natural gas reserve estimates and expectations about future +commodity prices. The Company concluded that its pressure +pumping segment was not subject to the negative events and +trends, to the same degree as the contract drilling segment, and +thus did not require further assessment of recoverability. +The Company performs the first step of its impairment +assessments by comparing the undiscounted cash flows for each +long-lived asset or asset group to its respective carrying +value. Based on the results of these impairment tests, the +carrying amounts of long-lived assets in the contract drilling +and oil and natural gas segments were determined to be +recoverable, except as described below. +The Company’s analysis indicated that the carrying amounts +of certain oil and natural gas properties were not recoverable +at various testing dates in 2009, 2008 and 2007. The +Company’s estimates of expected future net cash flows from +impaired properties are used in measuring the fair value of such +properties. The Company recorded impairment charges of +$3.7 million, $4.4 million and $3.9 million in +2009, 2008 and 2007, respectively, related to its oil and +natural gas properties. The Company determined the fair value of +the impaired assets using internally developed unobservable +inputs (level 3 inputs in the fair value hierarchy of fair value +accounting). +During 2009 and 2008, in connection with its long term planning +process, the Company evaluated its then-current fleet of +marketable drilling rigs and identified 23 and 22 rigs, +respectively, that it determined would no longer be marketed as +rigs. Additionally, in 2009, the Company identified one rig +which would be recommissioned in a different configuration. The +components comprising these rigs were evaluated, and those +components with continuing utility to the Company’s other +marketed rigs were transferred to other rigs or to yards to be +used as spare equipment. The remaining components of these rigs +were impaired and the associated net book value of +$10.5 million in 2009 and $10.4 million in 2008 was +expensed in the Company’s consolidated statements of +operations as an impairment charge. The components that were +impaired were estimated to have no fair value. The Company +determined the fair value of the impaired assets using +internally developed unobservable inputs (level 3 inputs in the +fair value hierarchy of fair value accounting). +F-13 +Table of Contents +5. +Goodwill +Goodwill by operating segment as of December 31, 2009 and +2008 and changes for the years then ended are as follows (in +thousands): +2009 +2008 +Contract Drilling: +Balance as of January 1: +Goodwill +$ +86,234 +$ +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Changes to goodwill +— +— +Balance as of December 31: +Goodwill +86,234 +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Drilling and Completion Fluids (Discontinued Operations): +Balance as of January 1: +Goodwill +9,964 +9,964 +Accumulated impairment losses +(9,964 +) +— +— +9,964 +Impairment +— +(9,964 +) +Balance as of December 31: +Goodwill +9,964 +9,964 +Accumulated impairment losses +(9,964 +) +(9,964 +) +— +— +Total goodwill as of December 31 +$ +86,234 +$ +86,234 +Goodwill is evaluated at least annually to determine if the fair +value of recorded goodwill has decreased below its carrying +value. For purposes of impairment testing, goodwill is evaluated +at the reporting unit level. The Company’s reporting units +for impairment testing have been determined to be its operating +segments. Goodwill as of December 31, 2009 and 2008 is +recorded in the Company’s contract drilling segment. Prior +to 2008, goodwill was also recorded in the Company’s +drilling and completion fluids segment. +In connection with its annual goodwill impairment assessment +performed as of December 31, 2008, the Company performed an +impairment test of goodwill recorded in its contract drilling +and drilling and completion fluids reporting units. In light of +the adverse market conditions affecting the Company’s +common stock price beginning in the fourth quarter of 2008 and +continuing into 2009, including a significant decrease in the +number of its rigs operating and a significant decline in oil +and natural gas commodity prices, the Company utilized a +discounted cash flow methodology to estimate the fair values of +its reporting units. In completing its first step of the +analysis, the Company used a three-year projection of discounted +cash flows, plus a terminal value determined using the constant +growth method to estimate the fair value of its reporting units. +In developing these fair value estimates, the Company applied +key assumptions, including an assumed discount rate of 13.99% +for all reporting units, an assumed long-term growth rate of +3.50% for the contract drilling reporting unit and an assumed +long-term growth rate of 2.00% for the drilling and completion +fluids reporting unit. +Based on the results of the first step of the impairment test in +2008, the Company concluded that no impairment was indicated in +its contract drilling reporting unit as the estimated fair value +of that reporting unit exceeded its carrying value. An +impairment was indicated in the drilling and completion fluids +reporting unit as the estimated fair value of that reporting +unit was less than its carrying value. In validating this +conclusion, the Company considered the results of its long-lived +asset impairment tests and performed sensitivity analyses of the +key assumptions used in deriving the respective fair values of +its reporting units. The Company then performed the second step +of the analysis of its drilling and completion fluids reporting +unit, which included allocating the +F-14 +Table of Contents +estimated fair value to the identifiable tangible and intangible +assets and liabilities of this reporting unit based on their +respective values. This allocation indicated that there was no +residual value for goodwill, and accordingly the Company +recorded an impairment charge of $9.964 million in the year +ended December 31, 2008. As discussed in Note 2, the +Company exited the drilling and completion fluids business on +January 20, 2010, and the impairment charge recorded in +2008 is included in the loss from discontinued operations in the +Company’s statement of operations for the year ended +December 31, 2008. +The Company again performed its annual goodwill impairment +assessment as of December 31, 2009 related to the remaining +$86.2 million in goodwill recorded in its contract drilling +reporting unit. In completing its first step of the analysis, +the Company used a three-year projection of discounted cash +flows, plus a terminal value determined using the constant +growth method to estimate the fair value of the reporting unit. +In developing this fair value estimate, the Company applied key +assumptions, including an assumed discount rate of 15.42% and an +assumed long-term growth rate of 3.50%. Based on the results of +the first step of the impairment test in 2009, the Company +concluded that no impairment was indicated in its contract +drilling reporting unit as the estimated fair value of that +reporting unit exceeded its carrying value. +In the event that market conditions weaken, the Company may be +required to record an impairment of goodwill in its contract +drilling reporting unit in the future, and such impairment could +be material. +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2009 and 2008 (in thousands): +2009 +2008 +Salaries, wages, payroll taxes and benefits +$ +14,744 +$ +30,334 +Workers’ compensation liability +66,015 +70,439 +Sales, use and other taxes +10,975 +12,105 +Insurance, other than workers’ compensation +11,261 +14,209 +Other +6,613 +5,658 +$ +109,608 +$ +132,655 +7. +Asset +Retirement Obligation +The Company records a liability for the estimated costs to be +incurred in connection with the abandonment of oil and natural +gas properties in the future. This liability is included in the +caption “other liabilities” on the consolidated +balance sheet. The following table describes the changes to the +Company’s asset retirement obligations during 2009 and 2008 +(in thousands): +2009 +2008 +Balance at beginning of year +$ +3,047 +$ +1,593 +Liabilities incurred +157 +516 +Liabilities settled +(354 +) +(424 +) +Accretion expense +118 +59 +Revision in estimated costs of plugging oil and natural gas wells +(13 +) +1,303 +Asset retirement obligation at end of year +$ +2,955 +$ +3,047 +8. +Borrowings +Under Revolving Credit Facility +In March 2009, the Company entered into an unsecured revolving +credit facility with a maximum borrowing capacity of +$240 million, including a letter of credit sublimit of +$150 million and a swing line sublimit of $40 million. +In addition, the aggregate borrowing and letter of credit +capacity under the revolving credit facility may, subject to the +terms and conditions set forth therein including the receipt of +additional commitments from lenders, be increased up to a +maximum amount not to exceed $450 million. +F-15 +Table of Contents +Interest is paid on the outstanding principal amount of +revolving credit facility borrowings at a floating rate based +on, at the Company’s election, LIBOR or a base rate. The +margin on LIBOR loans ranges from 3.00% to 4.00% and the margin +on base rate loans ranges from 2.00% to 3.00%, based on the +Company’s debt to capitalization ratio. At +December 31, 2009, the margin on LIBOR loans would have +been 3.00% and the margin on base rate loans would have been +2.00%. Any outstanding borrowings must be repaid at maturity on +January 31, 2012 and letters of credit may remain in effect +up to six months after such maturity date. This revolving credit +facility includes various fees, including a commitment fee on +the actual daily unused commitment (the commitment fee rate was +1.00% at December 31, 2009). +The Company incurred line of credit issuance costs of +approximately $6.2 million during 2009 in connection with +the revolving credit facility. These costs are being amortized +to interest expense over the contractual term of the revolving +credit facility. +There are customary representations, warranties, restrictions +and covenants associated with the revolving credit facility. +Financial covenants provide for a maximum debt to capitalization +ratio and a minimum interest coverage ratio. As of +December 31, 2009, the maximum debt to capitalization ratio +was 35% and the minimum interest coverage ratio was 3.00 to 1. +The Company does not expect that the restrictions and covenants +will impact its ability to operate or react to opportunities +that might arise. +As of December 31, 2009, the Company had no borrowings +outstanding under the revolving credit facility. The Company had +$46.3 million in letters of credit outstanding at +December 31, 2009 and, as a result, had available borrowing +capacity of approximately $194 million at that date. Each +domestic subsidiary of the Company has unconditionally +guaranteed the existing and future obligations of the Company +and each other guarantor under the revolving credit facility and +related loan documents, as well as obligations of the Company +and its subsidiaries under any interest rate swap contracts that +may be entered into with lenders party to the revolving credit +facility. +9. +Commitments, +Contingencies and Other Matters +Commitments — As of December 31, 2009, the +Company maintained letters of credit in the aggregate amount of +$46.3 million for the benefit of various insurance +companies as collateral for retrospective premiums and retained +losses which could become payable under the terms of the +underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically +renewed. As of December 31, 2009, no amounts had been drawn +under the letters of credit. +As of December 31, 2009, the Company had commitments to +purchase approximately $186 million of major equipment. +Contingencies — The Company’s contract +services operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in +personal injury or death, suspended drilling operations, damage +to, or destruction of equipment, damage to producing formations +and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains +general liability insurance coverage of $1.0 million per +occurrence in excess of a $1.0 million self-insured +retention for a total limit of $2.0 million per occurrence, +with $10.0 million of aggregate coverage and excess +liability and umbrella coverages up to $200 million per +occurrence and in the aggregate. The Company maintains a +$1.0 million per occurrence deductible on its workers’ +compensation, general liability and automobile liability +insurance coverages. Accrued expenses related to insurance +claims are set forth in Note 6. +The Company believes it is adequately insured for bodily injury +and property damage to others with respect to its operations. +However, such insurance may not be sufficient to protect the +Company against liability for all consequences of personal +injury, well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its rigs. However, it does not +cover the full replacement cost of the rigs and the Company does +not carry insurance against loss of earnings resulting from such +damage. There can be no assurance that such insurance coverage +will always be available on terms that are satisfactory to the +Company, if at all. +F-16 +Table of Contents +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic twelve +month renewals unless the Company notifies the Key Employee at +least ninety days before the end of such renewal period that the +term will not be extended. If a change in control of the Company +occurs during the term of the agreement and the Key +Employee’s employment is terminated (i) by the Company +other than for cause or other than automatically as a result of +death, disability or retirement, or (ii) by the Key +Employee for good reason (as those terms are defined in the +Change in Control Agreements), then the Key Employee shall +generally be entitled to, among other things: +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +10. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2007, 2008 +and 2009 as follows: +Per Share +Total +(in thousands) +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends +$ +0.44 +$ +68,561 +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +F-17 +Table of Contents +Per Share +Total +(in thousands) +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +On February 10, 2010, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.05 per share to be paid on March 30, 2010 to holders of +record as of March 15, 2010. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors +approved a stock buyback program authorizing purchases of up to +$250 million of the Company’s common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2007, the Company purchased +3,308,850 shares of its common stock under the program at a +cost of approximately $70.4 million. During the year ended +December 31, 2008, the Company purchased +3,502,047 shares of its common stock under the program at a +cost of approximately $66.3 million. During the year ended +December 31, 2009, the Company purchased 5,715 shares +of its common stock under the program at a cost of approximately +$79,000. As of December 31, 2009, the Company is authorized +to purchase approximately $113 million of the +Company’s outstanding common stock under the program. +Shares purchased under the program are accounted for as treasury +stock. +Additionally, the Company purchased 114,983, 152,235 and +20,269 shares of treasury stock from employees during 2009, +2008 and 2007, respectively. These shares were purchased at fair +market value upon the vesting of restricted stock to provide the +employees with the funds necessary to satisfy payroll tax +withholding obligations. The total purchase price for these +shares was approximately $1.5 million, $4.5 million +and $496,000 in 2009, 2008 and 2007, respectively. These +purchases were made pursuant to the terms of the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to +the stock buyback program. +11. +Stock-based +Compensation +The Company uses share-based payments to compensate employees +and non-employee directors. The Company recognizes the cost of +share-based payments under the fair-value-based method. Prior to +2009, share-based awards consisted of equity instruments in the +form of stock options, restricted stock or restricted stock +units, with all such awards subject to service conditions and, +in certain cases, performance conditions. Beginning in 2009, +share-based awards also include cash-settled performance unit +awards which are accounted for as liability awards. The Company +issues shares of common stock when vested stock options are +exercised, when restricted stock is granted and when restricted +stock units vest. +The Company’s shareholders have approved the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 +Plan”), and the Board of Directors adopted a resolution +that no future grants would be made under any of the +Company’s other previously existing plans. During 2008, the +Company amended the 2005 Plan to, among other +F-18 +Table of Contents +things, increase the total number of shares authorized for grant +from 6,250,000 to 10,250,000. The Company’s share-based +compensation plans at December 31, 2009 follow: +Shares +Shares +Authorized +Awards +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended +10,250,000 +4,980,068 +2,545,524 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +2,860,634 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +214,136 +— +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (“1996 Plan”) +— +35,000 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over one year for non-employee +directors and 3 to 4 years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2009, only +non-incentive stock options, restricted stock awards, restricted +stock units and performance unit awards had been granted under +the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Options granted under the 1996 Plan typically vest over two or +five years as dictated by the Compensation Committee. These +options have terms of no more than 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. +Stock Options — The Company estimates the grant +date fair values of stock options using the Black-Scholes-Merton +valuation model (“Black-Scholes”). Volatility +assumptions are based on the historic volatility of the +Company’s common stock over the most recent period equal to +the expected term of the options as of the date the options are +granted. The expected term assumptions are based on the +Company’s experience with respect to employee stock option +activity. Dividend yield assumptions are based on the expected +dividends at the time the options are granted. The risk-free +interest rate assumptions are determined by reference to United +States Treasury +F-19 +Table of Contents +yields. Weighted-average assumptions used to estimate grant date +fair values for stock options granted in the years ended +December 31, 2009, 2008 and 2007 follow: +2009 +2008 +2007 +Volatility +49.90 +% +37.04 +% +36.37 +% +Expected term (in years) +4.00 +4.17 +4.00 +Dividend yield +1.67 +% +2.27 +% +1.97 +% +Risk-free interest rate +1.67 +% +2.91 +% +4.55 +% +Stock option activity for the year ended December 31, 2009 +follows: +Weighted-average +Shares +exercise price +Outstanding at beginning of year +5,933,572 +$ +21.20 +Granted +1,037,500 +$ +13.12 +Exercised +(82,802 +) +$ +6.87 +Expired +(46,500 +) +$ +18.76 +Outstanding at end of year +6,841,770 +$ +20.17 +Exercisable at end of year +5,258,103 +$ +21.18 +Options outstanding at December 31, 2009 have an aggregate +intrinsic value of approximately $4.7 million and a +weighted-average remaining contractual term of 6.0 years. +Options exercisable at December 31, 2009 have an aggregate +intrinsic value of approximately $1.9 million and a +weighted-average remaining contractual term of 5.1 years. +Additional information with respect to options granted, vested +and exercised during the years ended December 31, 2009, +2008 and 2007 follows: +2009 +2008 +2007 +Weighted-average grant-date fair value of stock options granted +(per share) +$ +4.71 +$ +7.20 +$ +7.09 +Grant-date fair value of stock options vested during the year +(in thousands) +$ +6,973 +$ +6,761 +$ +5,613 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +510 +$ +45,240 +$ +3,186 +As of December 31, 2009, options to purchase +1,583,667 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2009 with respect +to these non-vested options that are expected to vest follows: +Aggregate intrinsic value +$2.7 million +Weighted-average remaining contractual term +8.95 years +Weighted-average remaining expected term +3.03 years +Weighted-average remaining vesting period +1.98 years +Unrecognized compensation cost +$7.1 million +Restricted Stock — For all restricted stock +awards to date, shares of common stock were issued when the +awards were made. Non-vested shares are subject to forfeiture +for failure to fulfill service conditions and, in certain cases, +performance conditions. Non-forfeitable dividends are paid on +non-vested shares of restricted stock. For restricted stock +awards made prior to 2008, the Company uses the +“graded-vesting” attribution method to recognize +periodic compensation cost over the vesting period. For +restricted stock awards made in 2008 and thereafter, the Company +uses the straight-line method to recognize periodic compensation +cost over the vesting period. +F-20 +Table of Contents +Restricted stock activity for the year ended December 31, +2009 follows: +Weighted- +average +Grant Date +Shares +Fair Value +Non-vested restricted stock outstanding at beginning of year +1,429,571 +$ +28.49 +Granted +603,600 +$ +13.75 +Vested +(745,715 +) +$ +27.97 +Forfeited +(55,555 +) +$ +26.65 +Non-vested restricted stock outstanding at end of year +1,231,901 +$ +21.67 +As of December 31, 2009, approximately +1,145,000 shares of non-vested restricted stock outstanding +are expected to vest. Additional information as of +December 31, 2009 with respect to these unvested shares +follows: +Aggregate intrinsic value +$ +17.6 million +Weighted-average remaining vesting period +1.54 years +Unrecognized compensation cost +$ +13.9 million +Restricted Stock Units — For all restricted +stock unit awards made to date, shares of common stock are not +issued until the units vest. Restricted stock units are subject +to forfeiture for failure to fulfill service conditions. +Non-forfeitable cash dividend equivalents are paid on non-vested +restricted stock units. +Restricted stock unit activity for the year ended +December 31, 2009 follows: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock units outstanding at beginning of +year +17,500 +$ +31.60 +Granted +6,500 +$ +14.39 +Vested +(5,833 +) +$ +31.60 +Forfeited +(2,000 +) +$ +14.39 +Non-vested restricted stock units outstanding at end of year +16,167 +$ +26.81 +Performance Unit Awards. On April 28, +2009, the Company granted performance unit awards to certain +executive officers (the “2009 Performance Units”). The +2009 Performance Units provide for those executive officers to +receive a cash payment upon the achievement of certain +performance goals established by the Company during a specified +period. The performance period for the 2009 Performance Units is +the period from April 1, 2009 through March 31, 2012. +The performance goals for the 2009 Performance Units are tied to +the Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee. These goals are +considered to be market conditions under the relevant accounting +standards. Generally, the recipients will receive a base payment +if the Company’s total shareholder return is positive and, +when compared to the peer group, is at or above the 25th +percentile but less than the 50th percentile; two times the base +if at or above the 50th percentile but less than the 75th +percentile, and four times the base if at the 75th percentile or +higher. The total base amount with respect to the 2009 +Performance Units is approximately $1.7 million. As the +2009 Performance Units are to be settled in cash at the end of +the performance period, the Company’s pro-rated obligation +is measured at estimated fair value at the end of each reporting +period and as of December 31, 2009 this pro-rated +obligation was approximately $859,000. +Dividends on Equity Awards — Non-forfeitable +cash dividends and dividend equivalents paid on equity awards +are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of restricted stock awards expected to vest. +F-21 +Table of Contents +• +Dividends are recognized as additional compensation cost for the +portion of restricted stock awards that are not expected to vest +or that ultimately do not vest. +• +Dividend equivalents are recognized as additional compensation +cost for restricted stock units. +12. +Leases +The Company incurred rent expense of $11.9 million, +$31.5 million and $27.6 million for the years 2009, +2008 and 2007, respectively. Rent expense is primarily related +to short-term equipment rentals that are passed through to +customers. The Company’s obligations under non-cancelable +operating lease agreements are not material to the +Company’s operations or cash flows. +13. +Income +Taxes +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2009, 2008 and 2007 are as follows (in +thousands): +2009 +2008 +2007 +Federal income tax expense (benefit): +Current +$ +(117,493 +) +$ +117,367 +$ +169,634 +Deferred +103,574 +57,879 +36,911 +(13,919 +) +175,246 +206,545 +State income tax expense (benefit): +Current +(1,883 +) +6,475 +16,174 +Deferred +(1,875 +7,070 +987 +(3,758 +) +13,545 +17,161 +Foreign income tax expense (benefit): +Current +338 +4,256 +5,220 +Deferred +(256 +) +443 +424 +82 +4,699 +5,644 +Total income tax expense (benefit): +Current +(119,038 +) +128,098 +191,028 +Deferred +101,443 +65,392 +38,322 +Total income tax expense (benefit) +$ +(17,595 +) +$ +193,490 +$ +229,350 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2009, 2008 and 2007 is summarized as follows: +2009 +2008 +2007 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +4.7 +1.7 +1.4 +Permanent differences +(5.7 +) +(1.2 +) +(1.6 +) +Other, net +0.1 +(0.2 +) +(0.3 +) +Effective tax rate +34.1 +% +35.3 +% +34.5 +% +F-22 +Table of Contents +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +December 31, +2009 +Change +2008 +Change +2007 +Change +2006 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +— +$ +— +$ +— +$ +(374 +) +$ +374 +$ +(1,496 +) +$ +1,870 +Workers’ compensation allowance +24,624 +(1,360 +) +25,984 +(602 +) +26,586 +223 +26,363 +Embezzlement costs +773 +45 +728 +68 +660 +(13,634 +) +14,294 +Other +18,843 +(2,780 +) +21,623 +3,219 +18,404 +3,903 +14,501 +44,240 +(4,095 +) +48,335 +2,311 +46,024 +(11,004 +) +57,028 +Non-current: +Net operating loss carryforwards +4,872 +4,872 +— +— +— +(374 +) +374 +AMT credit +— +— +— +(118 +) +118 +— +118 +Expense associated with employee stock options +9,129 +2,500 +6,629 +1,381 +5,248 +2,186 +3,062 +Federal benefit of foreign deferred tax liabilities +9,160 +(256 +) +9,416 +443 +8,973 +424 +8,549 +Federal benefit of state deferred tax liabilities +9,772 +2,702 +7,070 +1,643 +5,427 +735 +4,692 +Other +9,485 +4,120 +5,365 +614 +4,751 +704 +4,047 +42,418 +13,938 +28,480 +3,963 +24,517 +3,675 +20,842 +Total deferred tax assets +86,658 +9,843 +76,815 +6,274 +70,541 +(7,329 +) +77,870 +Deferred tax liabilities: +Current: +Other +(11,363 +) +1,044 +(12,407 +) +(1,753 +) +(10,654 +) +(2,493 +) +(8,161 +) +Non-current: +Property and equipment basis difference +(413,113 +) +(110,786 +) +(302,327 +) +(70,362 +) +(231,965 +) +(28,465 +) +(203,500 +) +Other +(10,961 +) +(7,091 +) +(3,870 +) +8,172 +(12,042 +) +(6,741 +) +(5,301 +) +(424,074 +) +(117,877 +) +(306,197 +) +(62,190 +) +(244,007 +) +(35,206 +) +(208,801 +) +Total deferred tax liabilities +(435,437 +) +(116,833 +) +(318,604 +) +(63,943 +) +(254,661 +) +(37,699 +) +(216,962 +) +Net deferred tax liability +$ +(348,779 +) +$ +(106,990 +) +$ +(241,789 +) +$ +(57,669 +) +$ +(184,120 +) +$ +(45,028 +) +$ +(139,092 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2009 and +2008 to be realized as a result of the reversal of existing +taxable temporary differences giving rise to deferred tax +liabilities and the generation of taxable income; therefore, no +valuation allowance is necessary. +Other deferred tax assets consist primarily of the tax effect of +various allowance accounts and tax-deferred expenses expected to +generate future tax benefit of approximately $28 million. +Other deferred tax liabilities consist +F-23 +Table of Contents +primarily of the tax effect of receivables from insurance +companies and tax-deferred income not yet recognized for tax +purposes. +For income tax purposes, the Company generated approximately +$450 million of Federal and state net operating losses +during the year ended December 31, 2009. Of this amount, +approximately $378 million will be carried back to prior +years, and the remaining balance can be carried forward to +future years. The net operating losses that can be carried +forward, if unused, are scheduled to expire as follows: +2014 — $7 million; 2019 — +$15 million and 2029 — $50 million. +The Company adopted a new accounting standard on January 1, +2007 which clarified the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribed a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of this standard in 2007, the Company +reduced a reserve for an uncertain tax position related to a +prior business combination that had originally been recorded as +goodwill (see Note 5). The impact of adjustments to +reserves with respect to other uncertain tax positions was not +material. As of December 31, 2009, the Company had no +unrecognized tax benefits. The Company has established a policy +to account for interest and penalties related to uncertain +income tax positions as operating expenses. As of +December 31, 2009, the tax years ended December 31, +2006 through December 31, 2008 are open for examination by +U.S. taxing authorities. As of December 31, 2009, the +tax years ended December 31, 2005 through December 31, +2008 are open for examination by Canadian taxing authorities. +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $2.8 million in 2009, $4.5 million in +2008 and $4.0 million in 2007 for the Company’s cash +contributions to the plan. +15. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to three business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services and (iii) the +investment, on a working interest basis, in oil and natural gas +properties. Each of these segments represents a distinct type of +business. These segments have separate management teams which +report to the Company’s chief operating decision maker. The +results of operations in these segments are regularly reviewed +by the chief operating decision maker for purposes of +determining resource allocation and assessing performance. As +discussed in Note 2, the Company exited the drilling and +completion fluids services business which previously was +reported as a business segment in January 2010. Operating +results for that business for the years ended December 31, +2009, 2008 and 2007 are presented as discontinued operations in +the consolidated statements of operations. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2009, the Company +had 341 marketable land-based drilling rigs, of which 73 of the +drilling rigs were based in west Texas and southeastern New +Mexico; 100 in north central and east Texas, northern Louisiana +and Mississippi; 56 in the Rocky Mountain region (Colorado, +Utah, Wyoming, Montana and North Dakota); 49 in south Texas; 28 +in the Texas panhandle, Oklahoma and Arkansas; 20 in western +Canada; and 15 in the Appalachian Basin. +For the years ended December 31, 2009, 2008 and 2007, +contract drilling revenue earned in Canada was +$45.4 million, $88.5 million and $72.9 million, +respectively. Additionally, we had long-lived assets within our +contract drilling segment located in Canada of +$69.2 million and $67.2 million as of +December 31, 2009 and 2008, respectively. +Pressure Pumping — The Company provides +pressure pumping services primarily in the Appalachian Basin. +Pressure pumping services consist primarily of well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Well stimulation involves processes inside a +well designed to enhance the flow of oil, natural gas, or other +desired substances from the well. Cementing is the process of +inserting material between the hole and the pipe to center and +stabilize the pipe in the hole. +F-24 +Table of Contents +Oil and Natural Gas — The Company has been +engaged in the development, exploration, acquisition and +production of oil and natural gas. Through October 31, +2007, the Company served as operator with respect to several +properties and was actively involved in the development, +exploration, acquisition and production of oil and natural gas. +Effective November 1, 2007 the Company sold the related +operations portion of its exploration and production business. +The Company continues to own and invest in oil and natural gas +assets as a working interest owner. The Company’s oil and +natural gas interests are located primarily in Texas and New +Mexico. +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Revenues: +Contract drilling +$ +600,423 +$ +1,808,600 +$ +1,744,884 +Pressure pumping +161,441 +217,494 +202,812 +Oil and natural gas +21,218 +42,360 +41,637 +Total segment revenues +783,082 +2,068,454 +1,989,333 +Elimination of intercompany revenues(a) +(1,136 +) +(4,574 +) +(3,237 +) +Total revenues +$ +781,946 +$ +2,063,880 +$ +1,986,096 +Income (loss) from continuing operations before income taxes: +Contract drilling +$ +(11,219 +) +$ +520,636 +$ +558,792 +Pressure pumping +1,017 +42,019 +64,257 +Oil and natural gas +950 +13,711 +10,998 +(9,252 +) +576,366 +634,047 +Corporate and other +(35,577 +) +(34,596 +) +(31,124 +) +Embezzlement recoveries(b) +— +— +43,955 +Net (loss) gain on asset disposals(c) +(3,385 +) +4,163 +16,432 +Interest income +381 +1,553 +2,351 +Interest expense +(4,148 +) +(630 +) +(2,187 +) +Other +426 +502 +363 +Income (loss) from continuing operations before income taxes +$ +(51,555 +) +$ +547,358 +$ +663,837 +Identifiable assets: +Contract drilling +$ +2,129,567 +$ +2,255,421 +$ +2,132,910 +Pressure pumping +213,094 +210,805 +154,120 +Oil and natural gas +25,355 +31,760 +37,885 +Corporate and other(d) +294,136 +214,831 +140,284 +Total assets +$ +2,662,152 +$ +2,712,817 +$ +2,465,199 +Depreciation, depletion and impairment: +Contract drilling +$ +248,424 +$ +239,700 +$ +213,812 +Pressure pumping +27,589 +19,600 +14,311 +Oil and natural gas +12,927 +15,856 +17,410 +Corporate and other +907 +834 +813 +Total depreciation, depletion and impairment +$ +289,847 +$ +275,990 +$ +246,346 +F-25 +Table of Contents +Years Ended December 31, +2009 +2008 +2007 +Capital expenditures: +Contract drilling +$ +395,376 +$ +360,645 +$ +539,506 +Pressure pumping +43,144 +61,289 +47,582 +Oil and natural gas +7,341 +22,981 +17,516 +Corporate and other +6,785 +511 +— +Total capital expenditures +$ +452,646 +$ +445,426 +$ +604,604 +(a) +Includes contract drilling intercompany revenues related to +drilling services provided for wells in which the Company owns a +working interest. +(b) +The Company’s former CFO has pleaded guilty to criminal +charges and has been sentenced and is serving a term of +imprisonment arising out of his embezzlement of funds from the +Company prior to his termination in 2005. The net embezzlement +recovery in 2007 includes the recognition of the recovery of +assets seized by a court appointed receiver, net of related +professional fees. +(c) +Net gains or losses associated with the disposal of assets +relate to corporate strategy decisions of the executive +management group. Accordingly, the related gains or losses have +been separately presented and excluded from the results of +specific segments. +(d) +Corporate and other assets primarily include identifiable assets +associated with the Company’s former drilling and +completion fluids segment as well as cash on hand managed by the +parent corporation and certain deferred Federal income tax +assets. +16. +Concentrations +of Credit Risk +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial +institutions. At December 31, 2009 and 2008, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2009 +2008 +Deposits in FDIC and SIPC-insured institutions under insurance +limits +$ +20,543 +$ +588 +Deposits in FDIC and SIPC-insured institutions over insurance +limits +47,376 +79,387 +Deposits in foreign banks +4,383 +18,805 +72,302 +98,780 +Less outstanding checks and other reconciling items +(22,425 +) +(17,557 +) +Cash and cash equivalents +$ +49,877 +$ +81,223 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2009, 2008, or 2007. The Company recognized +bad debt expense for 2009, 2008 and 2007 of $3.8 million, +$4.4 million and $2.9 million, respectively. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +F-26 +Table of Contents +17. +Related +Party Transactions +Joint Operation of Oil and Natural Gas +Properties — Through October 31, 2007, the +Company served as operator with respect to several properties +and was actively involved in the development, exploration, +acquisition and production of oil and natural gas. Effective +November 1, 2007, the Company sold the operations portion +of its exploration and production business. The Company +continues to own and invest in oil and natural gas assets as a +working interest owner. During the time that the Company served +as operator, it served as operator with respect to certain oil +and natural gas properties in which certain of its affiliated +persons have participated, either individually or through +entities they control. These participations were typically +through working interests in prospects or properties originated +or acquired by Patterson Petroleum LLC, a wholly owned +subsidiary of Patterson-UTI Energy, Inc. +During the time that the Company served as operator, sales of +working interests to affiliated parties were made by the Company +at its cost, comprised of the Company’s costs of acquiring +and preparing the working interests for sale plus a promote fee +in some cases. These costs were paid by the working interest +owners on a pro rata basis based upon their working interest +ownership percentage. The price at which working interests were +sold to affiliated persons was the same price at which working +interests were sold to unaffiliated persons except that in some +cases the affiliated persons also paid a promote fee. The +affiliated persons received oil and natural gas production +revenue (net of royalty) of $19.0 million from these +properties in 2007. These persons or entities in turn paid for +joint operating costs (including drilling and other development +expenses) of $9.2 million incurred in 2007. +18. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2008 +Operating revenues +$ +472,004 +$ +487,538 +$ +572,798 +$ +531,540 +Operating income +119,191 +122,364 +166,126 +138,252 +Income from continuing operations, net of income taxes +76,354 +75,184 +110,047 +92,282 +Income (loss) from discontinued operations, net of income taxes +1,055 +6,238 +(1,301 +) +(12,790 +) +Net income +77,409 +81,422 +108,746 +79,492 +Basic income (loss) per common share: +From continuing operations +$ +0.50 +$ +0.48 +$ +0.71 +$ +0.60 +From discontinued operations +$ +0.01 +$ +0.04 +$ +(0.01 +) +$ +(0.08 +) +Net income +$ +0.51 +$ +0.52 +$ +0.70 +$ +0.52 +Diluted income (loss) per common share: +From continuing operations +$ +0.49 +$ +0.48 +$ +0.70 +$ +0.60 +From discontinued operations +$ +0.01 +$ +0.04 +$ +(0.01 +) +$ +(0.08 +) +Net income +$ +0.50 +$ +0.52 +$ +0.69 +$ +0.52 +F-27 +Table of Contents +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2009 +Operating revenues +$ +268,209 +$ +140,497 +$ +159,671 +$ +213,569 +Operating income (loss) +25,154 +(25,855 +) +(24,619 +) +(22,894 +) +Income (loss) from continuing operations, net of income taxes +15,835 +(16,891 +) +(16,814 +) +(16,090 +) +Income (loss) from discontinued operations, net of income taxes +368 +(852 +) +(1,766 +) +(2,080 +) +Net income (loss) +16,203 +(17,743 +) +(18,580 +) +(18,170 +) +Basic income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income (loss) +$ +0.10 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +Diluted income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income (loss) +$ +0.10 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +As discussed in Note 2, the Company exited the drilling and +completion fluids services business in January 2010. The results +of operations related to the drilling and completion fluids +operating segment have been reclassified and presented as +discontinued operations in the quarterly financial information +above. +F-28 +Table of Contents +Schedule of Valuation and Qualifying Accounts Disclosure +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND QUALIFYING +ACCOUNTS +Charged to +Beginning +Costs and +Ending +Description +Balance +Expenses +Deductions(1) +Balance +(In thousands) +Year Ended December 31, 2009 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +9,330 +$ +4,700 +$ +3,119 +$ +10,911 +Year Ended December 31, 2008 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,014 +$ +4,350 +$ +5,034 +$ +9,330 +Year Ended December 31, 2007 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +7,484 +$ +2,550 +$ +20 +$ +10,014 +(1) +Uncollectible accounts written off net of recoveries. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 19, 2010 +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 +February 19, 2010. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +Table of Contents +EXHIBIT INDEX +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.6 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.8 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.9 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time.* +10 +.10 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.11 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.12 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +Table of Contents +10 +.13 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.14 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.15 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.16 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.19 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.20 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.21 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +Credit Agreement dated March 20, 2009, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer, swing line lender +and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC +Bank USA, N.A., as lender, Bank of America, N.A., as syndication +agent, letter of credit issuer and lender, and The Bank of +Tokyo-Mitsubishi UFJ, Ltd. as documentation agent and lender +(filed March 25, 2009 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.24 +Commitment Increase and Joinder Agreement dated June 19, +2009, among the Company, as borrower, Regions Bank as the new +lender, Bank of America, N.A. as a letter of credit issuer and +Wells Fargo Bank, N.A., as administrative agent, letter of +credit issuer, swing line lender and lender (filed August 4, +2009 as Exhibit 10.2 to the Company’s Quarterly Report on +Form 10-Q +and incorporated herein by reference). +10 +.25 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +Table of Contents +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2009, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Operations, (iii) the Consolidated Statements +of Changes in Stockholders’ Equity, (iv) the +Consolidated Statements of Cash Flows, (v) Notes to +Consolidated Financial Statements, tagged as blocks of text, and +(vi) Valuation and Qualifying Accounts. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/filing_metadata.csv b/raw/filings/0000889900/2009/0000950123-10-014515/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..639a3d600f0767f4d3bc78f2a8e18be1698c5f53 --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2010-02-19,2009-12-31,2010-02-19T20:09:48.000Z,0000950123-10-014515,d70467e10vk.htm,FORM 10-K,3825329,1,0,https://www.sec.gov/Archives/edgar/data/889900/000095012310014515/d70467e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095012310014515/,2009,2009,1 diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/item1.txt b/raw/filings/0000889900/2009/0000950123-10-014515/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..2a7b5b87bed5d225d14a88c584dca7c10f9f7923 --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/item1.txt @@ -0,0 +1,657 @@ +Item 1. +Business +Available +Information +This Report, along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Exchange Act, are available +free of charge through our Internet website (www.patenergy.com) +as soon as reasonably practicable after we electronically file +such material with, or furnish it to, the SEC. The information +contained on our website is not part of this Report or other +filings that we make with the SEC. You may read and copy any +materials we file with the SEC at the SEC’s Public +Reference Room at 100 F Street, NE, Washington, DC +20549. You may obtain information on the operation of the Public +Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site (www.sec.gov) that contains +reports, proxy and information statements and other information +regarding issuers that file electronically with the SEC. +1 +Table of Contents +Overview +We own and operate one of the largest fleets of land-based +drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, +Utah, Wyoming, Montana, North Dakota, Pennsylvania, West +Virginia and western Canada. +As of December 31, 2009, we had a drilling fleet that +consisted of 341 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drill pipe and drilling rig components. +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 +also own and invest in oil and natural gas assets as a working +interest owner. Our oil and natural gas interests are located +primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We exited the drilling and +completion fluids services business on January 20, 2010 and +sold substantially all of the assets, other than billed accounts +receivable, of that business. +Industry +Segments +Our revenues, operating profits and identifiable assets have +been primarily attributable to four industry segments: +• +contract drilling services, +• +pressure pumping services, +• +oil and natural gas exploration and production, and. +• +drilling and completion fluids services. +On January 20, 2010, we exited the drilling and completion +fluids services business and ceased operations in that segment. +As a result of the sale of this business, the historical results +of operations for this segment have been reclassified and are +presented as discontinued operations in this Report. +All of our industry segments had operating profits in 2007. In +2008, except for our drilling and completion fluids services +segment, all of our industry segments had operating profits. In +2009, our pressure pumping services and oil and natural gas +exploration and production segments had operating profits and +our contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2009, we had 341 marketable land-based +drilling rigs based in the following regions: +• +73 in west Texas and southeastern New Mexico, +• +100 in north central and east Texas, northern Louisiana and +Mississippi, +• +56 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana and North Dakota), +• +49 in south Texas and southern Louisiana, +2 +Table of Contents +• +28 in the Texas panhandle, Oklahoma and Arkansas, +• +15 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 30,000 feet. +Of these drilling rigs, 107 are electric rigs and 234 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. We also have a substantial inventory of drill pipe and +drilling rig components, which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.3 billion during the last three years on capital +expenditures to (1) build new land drilling rigs and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2009, 2008 and 2007, we spent approximately +$395 million, $361 million and $540 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the specifications of the +rig selected for a particular job. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well +basis or a term basis. +Well-to-well +contracts are generally short-term in nature and cover the +drilling of a single well or a series of wells. Term contracts +are entered into for a specified period of time (frequently one +to three years) and provide for the use of the drilling rig to +drill multiple wells. During 2009, our average number of days to +drill a well (which includes moving to the drill site, rigging +up and rigging down) was approximately 20 days. +Our 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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. Generally, we +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. +Generally, the customers indemnify us against claims that might +arise from other surface and subsurface pollution. Each drilling +contract contains the actual terms setting forth our rights and +obligations and those of the customer, any of which rights and +obligations may deviate from what is customary due to industry +conditions or other factors. +Our drilling contracts provide for payment on a daywork, +footage, or turnkey basis, or a combination thereof. In each +case, we provide the rig and crews. Except for two wells drilled +under footage contracts in 2009, all of the wells drilled during +the years ended December 31, 2009, 2008 and 2007 were +drilled under daywork contracts. Our bid for each job 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. +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. Except for two wells drilled under footage +contracts in 2009, all of the wells we drilled in 2009, 2008 and +2007 were under daywork contracts. +3 +Table of Contents +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the agreed depth. If we drill the well in +less time than estimated, we have the opportunity to improve our +profits over those that would be attainable under a daywork +contract. Profits are reduced and losses may be incurred if the +well requires more days to drill to the contracted depth than +estimated. Footage contracts generally contain greater risks for +a drilling contractor than daywork contracts. Under footage +contracts, the drilling contractor typically assumes certain +risks associated with loss of the well from fire, blowouts and +other risks. We drilled two wells under footage contracts in +2009, and we did not drill any wells under footage contracts in +2008 or 2007. +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed scope of +the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey +contracts in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2009 +2008 +2007 +Average rigs operating per day(1) +91 +254 +244 +Number of rigs operated during the year +243 +315 +338 +Number of wells drilled during the year +1,539 +4,218 +4,237 +Number of operating days(2) +33,394 +93,068 +89,095 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +(2) +Includes standby days under term contracts where revenue was +earned but the rig was not working. The number of these standby +days under term contracts was 2,070 in 2009, 486 in 2008 and +zero in 2007. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2009 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +59 +9 +68 +12,000 to 15,999 +189 +8 +197 +16,000 to 30,000 +73 +— +73 +Totals +321 +20 +341 +At December 31, 2009, we owned and operated 323 trucks and +417 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and generally +enhances the efficiency of our contract drilling operations, +particularly in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, Oklahoma, +Wyoming, Utah, Pennsylvania and western Canada. +4 +Table of Contents +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Most wells drilled in the Appalachian Basin +require some form of fracturing or other stimulation to enhance +the flow of oil and natural gas by pumping fluids under pressure +into the well bore. Appalachian Basin wells typically require +cementing services. The cementing process inserts material +between the wall of the well bore and the casing to center and +stabilize the casing. +Equipment — Our pressure pumping equipment at +December 31, 2009 includes equipment used in providing +hydraulic and nitrogen fracturing services as well as cementing +services as follows: +Hydraulic fracturing equipment: +• +20 quintiplex pump trailers (45,000 hydraulic horsepower), +• +69 triplex pumper trucks (82,800 hydraulic horsepower), +• +35 blender trucks, +• +4 blender trailers, +• +32 bulk acid trucks/acid pumper trucks, +• +70 bulk sand trucks, +• +19 sand pneumatic trucks, +• +6 sand pneumatic trailers, +• +15 flatbed material trucks, +• +30 connection trucks, +• +1 shale fracturing hydration trailer, +• +3 shale fracturing manifold trailers, +• +1 shale fracturing iron trailer, +• +15 shale fracturing sand field bins with conveyors, and +• +3 shale fracturing large conveyors. +Nitrogen fracturing equipment: +• +59 nitrogen pumper trucks (35,400 hydraulic horsepower), +• +30 bulk nitrogen trucks, and +• +9 bulk nitrogen tractor trailer combinations, +Cementing equipment: +• +44 cement pumper trucks, and +• +51 bulk cement trucks. +In addition to the equipment listed above, we had 45 tractors at +December 31, 2009 which are used in all of the lines of +business within our pressure pumping segment. +Oil and +Natural Gas Interests +We have been engaged in the development, exploration, +acquisition and production of oil and natural gas. Through +October 31, 2007, we served as operator with respect to +several properties and were actively involved in +5 +Table of Contents +the development, exploration, acquisition and production of oil +and natural gas. Effective November 1, 2007, we sold the +related operations portion of our exploration and production +business, which was the portion of our business that actively +managed the development, exploration, acquisition and production +of oil and natural gas. We continue to own and invest in oil and +natural gas assets as a working interest owner. Our oil and +natural gas interests are located primarily in producing regions +of Texas and New Mexico. +Drilling +and Completion Fluids Operations +Prior to exiting the business in January 2010, we provided +drilling fluids, completion fluids and related services to oil +and natural gas operators offshore in the Gulf of Mexico and on +land in Texas, New Mexico, Oklahoma and Louisiana. +Customers +The customers of each of our oil and natural gas service +business segments are oil and natural gas operators. Our +customer base includes both major and independent oil and +natural gas operators. During 2009, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly +competitive. Historically, available equipment used in these +businesses has frequently exceeded demand in our markets. The +price for our services is a key competitive factor in our +markets, in part because equipment used in our businesses can be +moved from one area to another in response to market conditions. +In addition to price, we believe availability and condition of +equipment, quality of personnel, service quality and safety +record are key factors in determining which contractor is +awarded a job in the markets in which we operate. We expect that +the market for land drilling and pressure pumping services will +continue to be competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, and +• +use of underground injection wells. +To date, applicable environmental laws and regulations in the +United States and Canada have not required the expenditure of +significant resources outside the ordinary course of business. +We do not anticipate any material capital expenditures for +environmental control facilities or extraordinary expenditures +to comply with environmental rules and regulations in the +foreseeable future. However, compliance costs under existing +laws or under any new requirements could become material, and we +could incur liability in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production. They could have an +adverse effect on our operations. Federal, state, foreign and +local environmental laws and regulations currently apply to our +operations and may become more stringent in the future. +We believe 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 operated by us or our +predecessors which may have resulted, or may result, in soil and +groundwater contamination in certain locations. Any +contamination found on, under or originating from the properties +may be subject to remediation requirements under Federal, state, +foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or +operators. In addition, it is possible we could be held +responsible for oil and natural gas properties in which we own +an interest but are not the operator. +6 +Table of Contents +Some of the environmental laws and regulations that are +applicable to our business operations are discussed in the +following paragraphs, but the discussion does not cover all +environmental laws and regulations that govern our operations. +In the United States, the Federal Comprehensive Environmental +Response Compensation and Liability Act of 1980, as amended, +commonly known as CERCLA, and comparable state statutes impose +strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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 working interest in +oil and natural gas properties in each of the areas in which +these interests are located. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may +subject a responsible party, such as us, to civil or criminal +actions. Although the liability for owners and operators is the +same under the Federal Water Pollution Act, the damages +recoverable under the Oil Pollution Act are potentially much +greater and can include natural resource damages. +In Canada, a variety of Canadian federal, provincial and +municipal laws and regulations impose, among other things, +restrictions, liabilities and obligations in connection with the +generation, handling, use, storage, transportation, treatment +and disposal of hazardous substances and wastes and in +connection with spills, releases and emissions of various +substances to the environment. These laws and regulations also +require that facility sites and other properties associated with +our operations be operated, maintained, abandoned and reclaimed +to the satisfaction of applicable regulatory authorities. In +addition, new projects or changes to existing projects may +require the submission and approval of environmental assessments +or permit applications. These laws and regulations are subject +to frequent change, and the clear trend is to place increasingly +stringent limitations on activities that may affect the +environment. +Our operations are also subject to Federal, state, foreign and +local laws, rules and regulations for the control of air +emissions, including the Federal Clean Air Act and the Canadian +Environmental Protection Act. We are aware of the increasing +focus of local, state, national and international regulatory +bodies on greenhouse gas (GHG) emissions and climate change +issues. We are also aware of legislation proposed by United +States lawmakers and the Canadian legislature to reduce GHG +emissions, as well as GHG emissions regulations enacted by the +U.S. Environmental Protection Agency and the Canadian +provinces of Alberta and British Columbia. We will continue to +monitor and assess any new policies, legislation or regulations +in the areas where we operate to determine the impact of GHG +emissions and climate change on our operations and take +appropriate actions, where necessary. Any direct and +7 +Table of Contents +indirect costs of meeting these requirements may adversely +affect our business, results of operations and financial +condition. +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, +• +fires, and +• +explosions. +These hazards could cause: +• +personal injury or death, +• +suspension of drilling operations, or +• +serious damage or destruction of the equipment involved and, in +addition to environmental damage, could cause substantial damage +to producing formations and surrounding areas. +Damage to the environment, including property contamination in +the form of either soil or ground water contamination, could +also result from our operations, particularly through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +In addition, we could become subject to liability for reservoir +damages. The occurrence of a significant event, including +pollution or environmental damages, could materially affect our +operations, cash flows and financial condition. +As a protection against operating hazards, we maintain insurance +coverage we believe to be adequate, including: +• +insurance for fire, windstorm and other risks of physical loss +to our rigs and other assets, +• +employer’s liability, +• +automobile liability, +• +commercial general liability insurance, and +• +workers compensation insurance. +We believe that we are adequately insured for bodily injury and +property damage to others with respect to our operations. Such +insurance, however, may not be sufficient to protect us against +liability for all consequences of: +• +personal injury, +• +well disasters, +• +extensive fire damage, +• +damage to the environment, or +• +other hazards. +We also carry insurance to cover physical damage to, or loss of, +our drilling rigs. Such insurance does not, however, cover the +full replacement cost of the rigs, and we do not carry insurance +against loss of earnings resulting +8 +Table of Contents +from such damage. In view of the difficulties that may be +encountered in renewing such insurance at reasonable rates, no +assurance can be given that: +• +we will be able to maintain the type and amount of coverage that +we believe to be adequate at reasonable rates, or +• +any particular types of coverage will be available. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +These contractual indemnifications, if obtained, may not be +supported by adequate insurance maintained by the customer. +Employees +We had approximately 4,200 full-time employees at +December 31, 2009. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada and, to a +lesser extent, our pressure pumping operations in the +Appalachian Basin, are subject to slow periods of activity +during the Spring thaw. +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. \ No newline at end of file diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/item13.txt b/raw/filings/0000889900/2009/0000950123-10-014515/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..97cbc88da95dc5aeea63960da2883c0ca43e0a25 --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/item13.txt @@ -0,0 +1,6 @@ +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/item9a.txt b/raw/filings/0000889900/2009/0000950123-10-014515/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..18f3ab3af47bfe387e58a1eded5ec3f223b731e4 --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/item9a.txt @@ -0,0 +1,3953 @@ +Item 9A. Our responsibility is to express opinions on these +financial statements, on the financial statement schedule, and +on the Company’s internal control over financial reporting +based on our integrated audits. We conducted our audits in +accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we +plan and perform the audits to obtain reasonable assurance about +whether the financial statements are free of material +misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test +basis, evidence supporting the amounts and disclosures in the +financial statements, assessing the accounting principles used +and significant estimates made by management, and evaluating the +overall financial statement presentation. Our audit of internal +control over financial reporting included obtaining an +understanding of internal control over financial reporting, +assessing the risk that a material weakness exists, and testing +and evaluating the design and operating effectiveness of +internal control based on the assessed risk. Our audits also +included performing such other procedures as we considered +necessary in the circumstances. We believe that our audits +provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 19, 2010 +F-2 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2009 +2008 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +49,877 +$ +81,223 +Accounts receivable, net of allowance for doubtful accounts of +$10,911 and $9,330 at December 31, 2009 and 2008, +respectively +164,498 +414,531 +Federal and state income taxes receivable +118,869 +10,175 +Inventory +6,941 +41,999 +Deferred tax assets, net +32,877 +35,928 +Assets held for sale +42,424 +— +Other +41,782 +57,518 +Total current assets +457,268 +641,374 +Property and equipment, net +2,110,402 +1,937,112 +Goodwill +86,234 +86,234 +Deposits on equipment purchases +914 +43,944 +Other +7,334 +4,153 +Total assets +$ +2,662,152 +$ +2,712,817 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +83,700 +$ +169,958 +Accrued expenses +109,608 +132,655 +Total current liabilities +193,308 +302,613 +Borrowings under revolving credit facility +— +— +Deferred tax liabilities, net +381,656 +277,717 +Other +5,488 +5,545 +Total liabilities +580,452 +585,875 +Commitments and contingencies (see Note 9) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 180,828,773 and 180,192,093 issued and 153,610,785 and +153,094,803 outstanding at December 31, 2009 and 2008, +respectively +1,808 +1,801 +Additional paid-in capital +781,635 +765,512 +Retained earnings +1,901,853 +1,970,824 +Accumulated other comprehensive income +14,996 +5,774 +Treasury stock, at cost, 27,217,988 shares and +27,097,290 shares at December 31, 2009 and 2008, +respectively +(618,592 +) +(616,969 +) +Total stockholders’ equity +2,081,700 +2,126,942 +Total liabilities and stockholders’ equity +$ +2,662,152 +$ +2,712,817 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +Year Ended December 31, +2009 +2008 +2007 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +599,287 +$ +1,804,026 +$ +1,741,647 +Pressure pumping +161,441 +217,494 +202,812 +Oil and natural gas +21,218 +42,360 +41,637 +Total operating revenues +781,946 +2,063,880 +1,986,096 +Operating costs and expenses: +Contract drilling +357,742 +1,038,327 +963,150 +Pressure pumping +111,414 +132,570 +105,273 +Oil and natural gas +7,341 +12,793 +10,864 +Depreciation, depletion and impairment +289,847 +275,990 +246,346 +Selling, general and administrative +56,621 +58,080 +54,665 +Embezzlement recoveries +— +— +(43,955 +) +Net loss (gain) on asset disposals +3,385 +(4,163 +) +(16,432 +) +Other operating expenses +3,810 +4,350 +2,875 +Total operating costs and expenses +830,160 +1,517,947 +1,322,786 +Operating income (loss) +(48,214 +) +545,933 +663,310 +Other income (expense): +Interest income +381 +1,553 +2,351 +Interest expense +(4,148 +) +(630 +) +(2,187 +) +Other +426 +502 +363 +Total other income (expense) +(3,341 +) +1,425 +527 +Income (loss) before income taxes +(51,555 +) +547,358 +663,837 +Income tax expense (benefit): +Current +(119,038 +) +128,098 +191,028 +Deferred +101,443 +65,392 +38,322 +Total income tax expense (benefit) +(17,595 +) +193,490 +229,350 +Income (loss) from continuing operations +(33,960 +) +353,868 +434,487 +Income (loss) from discontinued operations, net of income taxes +(4,330 +) +(6,799 +) +4,152 +Net income (loss) +$ +(38,290 +) +$ +347,069 +$ +438,639 +Basic income (loss) per common share: +Income (loss) from continuing operations +$ +(0.22 +) +$ +2.29 +$ +2.78 +Income (loss) from discontinued operations, net of income taxes +(0.03 +) +(0.04 +) +0.03 +Net income (loss) +$ +(0.25 +) +$ +2.25 +$ +2.81 +Diluted income (loss) per common share: +Income (loss) from continuing operations +$ +(0.22 +) +$ +2.27 +$ +2.75 +Income (loss) from discontinued operations, net of income taxes +(0.03 +) +(0.04 +) +0.03 +Net income (loss) +$ +(0.25 +) +$ +2.23 +$ +2.78 +Weighted average number of common shares outstanding: +Basic +152,069 +153,379 +154,755 +Diluted +152,069 +154,358 +156,612 +Cash dividends per common share +$ +0.20 +$ +0.60 +$ +0.44 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2006 +176,656 +$ +1,766 +$ +681,069 +$ +1,346,542 +$ +8,390 +$ +(475,301 +) +$ +1,562,466 +Comprehensive income: +Net income +— +— +— +438,639 +— +— +438,639 +Foreign currency translation adjustment, (net of tax of $6,755) +— +— +— +— +11,817 +— +11,817 +Total comprehensive income +— +— +— +438,639 +11,817 +— +450,456 +Issuance of restricted stock +601 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(101 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +230 +2 +2,048 +— +— +— +2,050 +Stock-based compensation +— +— +19,364 +— +— +— +19,364 +Tax benefit related to stock-based compensation +— +— +1,105 +— +— +— +1,105 +Payment of cash dividends +— +— +— +(68,561 +) +— +— +(68,561 +) +Purchase of treasury stock +— +— +— +— +— +(70,850 +) +(70,850 +) +Balance, December 31, 2007 +177,386 +1,773 +703,581 +1,716,620 +20,207 +(546,151 +) +1,896,030 +Comprehensive income: +Net income +— +— +— +347,069 +— +— +347,069 +Foreign currency translation adjustment, (net of tax of $8,368) +— +— +— +— +(14,433 +) +— +(14,433 +) +Total comprehensive income +— +— +— +347,069 +(14,433 +) +— +332,636 +Issuance of restricted stock +577 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(75 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +2,304 +23 +25,525 +— +— +— +25,548 +Stock-based compensation +— +— +20,131 +— +— +— +20,131 +Tax benefit related to stock-based compensation +— +— +16,280 +— +— +— +16,280 +Payment of cash dividends +— +— +— +(92,865 +) +— +— +(92,865 +) +Purchase of treasury stock +— +— +— +— +— +(70,818 +) +(70,818 +) +Balance, December 31, 2008 +180,192 +1,801 +765,512 +1,970,824 +5,774 +(616,969 +) +2,126,942 +Comprehensive income (loss): +Net loss +— +— +— +(38,290 +) +— +— +(38,290 +) +Foreign currency translation adjustment, (net of tax of $5,347) +— +— +— +— +9,222 +— +9,222 +Total comprehensive loss +— +— +— +(38,290 +) +9,222 +— +(29,068 +) +Issuance of restricted stock +604 +6 +(6 +) +— +— +— +— +Vesting of restricted stock units +6 +— +— +— +— +— +— +Forfeitures of restricted stock +(56 +) +— +— +— +— +— +— +Exercise of stock options +83 +1 +568 +— +— +— +569 +Stock-based compensation +— +— +18,565 +— +— +— +18,565 +Tax expense related to stock-based compensation +— +— +(3,004 +) +— +— +— +(3,004 +) +Payment of cash dividends +— +— +— +(30,681 +) +— +— +(30,681 +) +Purchase of treasury stock +— +— +— +— +— +(1,623 +) +(1,623 +) +Balance, December 31, 2009 +180,829 +$ +1,808 +$ +781,635 +$ +1,901,853 +$ +14,996 +$ +(618,592 +) +$ +2,081,700 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Year Ended December 31, +2009 +2008 +2007 +(In thousands) +Cash flows from operating activities: +Net income (loss) +$ +(38,290 +) +$ +347,069 +$ +438,639 +Adjustments to reconcile net income (loss) to net cash provided +by operating activities: +Depreciation, depletion and impairment +289,847 +275,990 +246,346 +Provision for bad debts +3,810 +4,350 +2,875 +Dry holes and abandonments +129 +1,617 +1,309 +Deferred income tax expense +101,443 +65,392 +38,322 +Stock-based compensation expense +18,214 +19,688 +18,873 +Net loss (gain) on asset disposals +3,385 +(4,163 +) +(16,432 +) +Tax expense related to stock-based compensation +(3,004 +) +— +— +Changes in operating assets and liabilities: +Accounts receivable +213,813 +(30,777 +) +100,429 +Income taxes receivable/payable +(108,664 +) +(11,258 +) +7,174 +Inventory and other assets +14,178 +2,498 +2,211 +Accounts payable +(52,673 +) +6,486 +(37,412 +) +Accrued expenses +(21,178 +) +(4,474 +) +(5,640 +) +Other liabilities +(92 +) +1,242 +1,434 +Net cash provided by operating activities of discontinued +operations +32,759 +1,344 +14,096 +Net cash provided by operating activities +453,677 +675,004 +812,224 +Cash flows from investing activities: +Acquisitions +— +— +(29,000 +) +Purchases of property and equipment +(452,646 +) +(445,426 +) +(604,604 +) +Proceeds from disposal of assets +3,359 +11,436 +34,054 +Net cash used in investing activities of discontinued operations +(54 +) +(3,286 +) +(2,912 +) +Net cash used in investing activities +(449,341 +) +(437,276 +) +(602,462 +) +Cash flows from financing activities: +Purchases of treasury stock +(1,623 +) +(70,818 +) +(70,850 +) +Dividends paid +(30,681 +) +(92,865 +) +(68,561 +) +Tax benefit related to stock-based compensation +— +16,280 +1,105 +Proceeds from borrowings under revolving credit facility +— +— +142,500 +Repayment of borrowings under revolving credit facility +— +(50,000 +) +(212,500 +) +Revolving credit facility issuance costs +(6,169 +) +— +— +Proceeds from exercise of stock options +569 +25,548 +2,050 +Net cash used in financing activities +(37,904 +) +(171,855 +) +(206,256 +) +Effect of foreign exchange rate changes on cash +2,222 +(2,084 +) +543 +Net increase (decrease) in cash and cash equivalents +(31,346 +) +63,789 +4,049 +Cash and cash equivalents at beginning of year +81,223 +17,434 +13,385 +Cash and cash equivalents at end of year +$ +49,877 +$ +81,223 +$ +17,434 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest expense +$ +(1,804 +) +$ +(323 +) +$ +(1,808 +) +Income taxes +14,029 +(126,331 +) +(176,281 +) +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property +and equipment +$ +(25,110 +) +$ +(3,590 +) +$ +597 +Net (increase) decrease in deposits on equipment purchases +43,029 +(42,293 +) +23,095 +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., through 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, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +Pennsylvania, West Virginia and western Canada. The Company +provides pressure pumping services primarily in the Appalachian +Basin. The Company also owns and invests in oil and natural gas +assets as a working interest owner primarily in Texas and New +Mexico. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. Except for +wholly-owned subsidiaries, the Company has no controlling +financial interests in any entity which would require +consolidation. +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 its functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed contract method of accounting. The Company +follows the +percentage-of-completion +method of accounting for footage contract drilling arrangements. +Under the +percentage-of-completion +method, management estimates are relied upon in the +determination of the total estimated expenses to be incurred +drilling the well. Due to the nature of turnkey contract +drilling arrangements and risks therein, the Company follows the +completed contract method of accounting for such arrangements. +Under this method, all drilling 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. Except for two wells drilled under +footage contracts in 2009, all of the wells the Company drilled +during the years ended December 31, 2009, 2008 and 2007 +were under daywork contracts. +Accounts receivable — Trade accounts receivable +are recorded at the invoiced amount. 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 at least quarterly. Significant individual +accounts receivable balances and balances which have been +outstanding greater than 90 days are reviewed individually +for collectibility. Account balances, when determined to be +uncollectible, are charged against the allowance. +Inventories — Inventories at December 31, +2009 consist primarily of chemical products and sand to be used +in conjunction with the Company’s pressure pumping +activities. Inventories at December 31, 2008 consisted +primarily of chemical products to be used in conjunction with +the Company’s drilling and completion fluids activities. +The inventories are stated at the lower of cost or market, +determined by the +first-in, +first-out method. +F-7 +Table of Contents +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change when +equipment becomes idle. The estimated useful lives, in years, +are shown below: +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are +evaluated for impairment when certain triggering events or +changes in circumstances indicate that the carrying values may +not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and the economic operating viability +of the respective projects. If no progress has been made in +assessing the reserves and the economic operating viability of a +project after one year following the completion of drilling, the +Company considers the costs of the well to be impaired and +recognizes the costs as expense. Geological and geophysical +costs, including seismic costs, and costs to carry and retain +undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful +exploratory type wells, consisting of lease and well equipment, +lease acquisition costs and intangible development costs, are +depreciated, depleted and amortized on the +units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves of each respective field. +The Company reviews its proved oil and natural gas properties +for impairment when a triggering event occurs such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on +management’s expectation of future pricing over the lives +of the respective fields. These estimates are then reviewed by +an independent petroleum engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment +expense is measured and recognized as the difference between its +net book value and discounted cash flow. Unproved oil and +natural gas properties are reviewed quarterly to assess +potential 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 — Goodwill is considered to have an +indefinite useful economic life and is not amortized. The +Company assesses impairment of its goodwill at least annually or +on an interim basis if triggering events or circumstances +indicate that the fair value of the asset may have decreased +below its carrying value. As discussed in Note 5, the +Company determined that goodwill in its drilling and completion +fluids reporting unit was impaired in connection with its annual +impairment testing performed as of December 31, 2008. As +discussed in Note 2, the Company exited the drilling and +completion fluids business in January 2010, and this impairment +charge is included in the results of discontinued operations in +the consolidated statements of operations for the year ended +December 31, 2008. +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Disposals — Upon disposition of property and +equipment, the cost and related accumulated depreciation are +removed and any resulting gain or loss is reflected in the +consolidated statement of operations. +Net income (loss) per common share — The +Company provides a dual presentation of its net income (loss) +per common share in its consolidated statements of operations: +Basic net income (loss) per common share (“Basic EPS”) +and diluted net income (loss) per common share (“Diluted +EPS”). The Company adopted a new accounting standard on +January 1, 2009, which clarified that share-based payment +awards that entitle their holders to receive +F-8 +Table of Contents +non-forfeitable dividends before vesting should be considered +participating securities and, as such, should be included in the +calculation of +earnings-per-share +using the two-class method. All +earnings-per-share +data presented for the years ended December 31, 2008 and +2007 have been adjusted retrospectively to conform with this +accounting standard. The impact of this retrospective +application to the year ended December 31, 2008 was to +reduce Basic and Diluted EPS by $0.01. The impact of this +retrospective application to the year ended December 31, +2007 was to reduce Basic EPS by $0.02 and to reduce Diluted EPS +by $0.01. +Basic EPS excludes dilution and is computed by first allocating +earnings between common stockholders and holders of non-vested +shares of restricted stock. Basic EPS is then determined by +dividing the earnings attributable to common stockholders by the +weighted average number of common shares outstanding during the +period, excluding non-vested shares of restricted stock. +Diluted EPS is based on the weighted average number of common +shares outstanding plus the dilutive effect of potential common +shares, including stock options, non-vested shares of restricted +stock and restricted stock units. The dilutive effect of stock +options and restricted stock units is determined using the +treasury stock method. The dilutive effect of non-vested shares +of restricted stock is based on the more dilutive of the +treasury stock method or the two-class method, assuming a +reallocation of undistributed earnings to common stockholders +after considering the dilutive effect of potential common shares +other than non-vested shares of restricted stock. +The following table presents information necessary to calculate +income (loss) from continuing operations per share, income(loss) +from discontinued operations per share and net income (loss) per +share for the years ended December 31, 2009, 2008 and 2007 +as well as potentially dilutive securities excluded from the +weighted average number of diluted common shares outstanding, as +their inclusion would have been anti-dilutive (in thousands, +except per share amounts): +2009 +2008 +2007 +BASIC EPS: +Income (loss) from continuing operations +$ +(33,960 +) +$ +353,868 +$ +434,487 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +313 +(3,279 +) +(3,886 +) +Income (loss) from continuing operations attributed to common +stockholders +$ +(33,647 +) +$ +350,589 +$ +430,601 +Income (loss) from discontinued operations, net +$ +(4,330 +) +$ +(6,799 +) +$ +4,152 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +38 +64 +(37 +) +Income (loss) from discontinued operations attributed to common +stockholders +$ +(4,292 +) +$ +(6,735 +) +$ +4,115 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,069 +153,379 +154,755 +Basic income (loss) from continuing operations per common share +$ +(0.22 +) +$ +2.29 +$ +2.78 +Basic income (loss) from discontinued operations per common share +(0.03 +) +(0.04 +) +0.03 +Basic net income (loss) per common share +$ +(0.25 +) +$ +2.25 +$ +2.81 +F-9 +Table of Contents +2009 +2008 +2007 +DILUTED EPS: +Income (loss) from continuing operations attributed to common +stockholders +$ +(33,647 +) +$ +350,589 +$ +430,601 +Add incremental earnings related to potential common shares +— +15 +39 +Adjusted income (loss) from continuing operations attributed to +common stockholders +$ +(33,647 +) +$ +350,604 +$ +430,640 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,069 +153,379 +154,755 +Add dilutive effect of potential common shares +— +979 +1,857 +Weighted average number of diluted common shares outstanding +152,069 +154,358 +156,612 +Diluted income (loss) from continuing operations per common share +$ +(0.22 +) +$ +2.27 +$ +2.75 +Diluted income (loss) from discontinued operations per common +share +(0.03 +) +(0.04 +) +0.03 +Diluted net income (loss) per common share +$ +(0.25 +) +$ +2.23 +$ +2.78 +Potentially dilutive securities excluded as anti-dilutive +8,090 +2,455 +2,460 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. +The Company adopted a new accounting standard on January 1, +2007 which clarified the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribed a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of this standard in 2007, the Company +reduced a reserve for an uncertain tax position related to a +prior business combination that had originally been recorded as +goodwill in its contract drilling segment. The impact of this +adjustment was to reduce goodwill in the contract drilling +segment by approximately $2.9 million upon adoption of the +new standard. The impact of adjustments to reserves with respect +to other uncertain tax positions was not material. The +Company’s policy is to account for interest and penalties +with respect to income taxes as operating expenses. +Stock based compensation — The Company +recognizes the cost of share-based payments under the +fair-value-based method. Under this method, compensation cost +related to share-based payments is measured based on the +estimated fair value of the awards at the date of grant, net of +estimated forfeitures. This expense is recognized over the +expected life of the awards (See Note 11). +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Subsequent Events — The Company has performed +an evaluation of subsequent events through February 19, 2010 at +the time of issuance of the consolidated financial statements. +Recently Issued Accounting Standards — In June +2008, the FASB issued an accounting standard which clarifies +that share-based payment awards that entitle their holders to +receive non-forfeitable dividends before +F-10 +Table of Contents +vesting should be considered participating securities and, as +such, should be included in the calculation of basic +earnings-per-share +using the two-class method. Certain of the Company’s +share-based payment awards entitle the holders to receive +non-forfeitable dividends. This standard is effective for +financial statements issued for fiscal years beginning after +December 15, 2008, as well as interim periods within those +years, and became effective for the Company on January 1, +2009. The impact of the adoption of this standard is discussed +in this Note 1. +In December 2008, the SEC issued a Final Rule, Modernization +of Oil and Gas Reporting (“Final Rule”). The Final +Rule revises certain oil and gas reporting disclosures in +Regulation S-K +and +Regulation S-X +under the Securities Act, and the Exchange Act, as well as +Industry Guide 2. The amendments are designed to modernize and +update oil and gas disclosure requirements to align them with +current practices and changes in technology. The disclosure +requirements are effective for registration statements filed on +or after January 1, 2010 and for annual financial +statements filed on or after December 31, 2009. The Company +applied the provisions of the Final Rule in connection with its +December 31, 2009 oil and natural gas reserve estimation +process. The application of the Final Rule did not have a +material impact on the Company. +In April 2009, the FASB issued a staff position to provide +additional guidance for determining whether a market for a +financial asset is not active and a transaction is not +distressed for fair value measurements under generally accepted +accounting principles. The provisions of this staff position are +effective for financial statements issued for interim and annual +periods ending after June 15, 2009 and became effective for +the Company in the quarter ended June 30, 2009. The +adoption of this staff position did not have a material impact +on the Company. +In June 2009, the FASB issued a new accounting standard that +amends the accounting and disclosure requirements for the +consolidation of variable interest entities. This new standard +removes the previously existing exception from applying +consolidation guidance to qualifying special-purpose entities +and requires ongoing reassessments of whether an enterprise is +the primary beneficiary of a variable interest entity. Before +this new standard, generally accepted accounting principles +required reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for the Company on January 1, +2010. The adoption of this standard did not impact the +Company’s consolidated financial statements. +In June 2009, the FASB issued the FASB Accounting Standards +Codification (“Codification”). Effective for financial +statements issued for interim and annual periods ending after +September 15, 2009, the Codification became the source of +authoritative U.S. generally accepted accounting +principles. The FASB will no longer issue new standards in the +form of Statements, FASB Staff Positions or EITF Abstracts. +Instead, it will issue Accounting Standards Updates to update +the Codification. The adoption of the Codification did not +impact the Company’s consolidated financial statements. +Reclassifications — Certain reclassifications +have been made to the 2008 and 2007 consolidated financial +statements in order for them to conform with the 2009 +presentation. These reclassifications had no impact on the +Company’s financial position, results of operations or cash +flows. +2. +Discontinued +Operations +On January 20, 2010, the Company exited the drilling and +completion fluids services business, which had previously been +presented as one of the Company’s reportable operating +segments. On that date, the Company’s wholly owned +subsidiary, Ambar Lone Star Fluids Services LLC, completed the +sale of substantially all of its assets, excluding billed +accounts receivable. The sales price was approximately +$44.3 million, subject to any post-closing adjustments to +reflect the actual assets transferred as of the closing date. +Upon the Company’s exit from the drilling and completion +fluids services business, the Company classified its drilling +and completion fluids operating segment as a discontinued +operation. Accordingly, the results of operations of this +business have been reclassified and presented as results of +discontinued operations for all periods presented in these +consolidated financial statements. As of December 31, 2009, +the assets to be disposed of are considered held for sale and +are presented separately under the caption “Assets held for +sale” in the consolidated balance sheet. These assets are +included in the balance sheet at fair value less transaction +costs. The fair value of the assets to be disposed of was +estimated to be +F-11 +Table of Contents +approximately $44.3 million based on the expected sales +price described above. The source of this estimate was from a +third party and it is considered a level 2 input in the fair +value hierarchy of fair value accounting. Costs to sell the +disposal group were estimated to be $1.9 million. An impairment +charge of $1.9 million was recognized to reduce the carrying +value of the disposal group to its estimated fair value less +costs to sell. +Summarized operating results from discontinued operations for +the years ended December 31, 2009, 2008 and 2007 are shown +below (in thousands): +2009 +2008 +2007 +Drilling and completion fluids revenues +$ +79,786 +$ +145,246 +$ +128,098 +Income (loss) before income taxes +$ +(6,538 +) +$ +(4,410 +) +$ +6,970 +Income tax benefit (expense) +2,208 +(2,389 +) +(2,818 +) +Income (loss) from discontinued operations +$ +(4,330 +) +$ +(6,799 +) +$ +4,152 +The loss before income taxes in 2008 includes $9.96 million +in non-deductible charges resulting from the impairment of +goodwill. As a result, income tax expense was incurred for the +year despite the fact that the discontinued operation had a +pre-tax book loss. +The components of assets held for sale at December 31, 2009 +are shown below (in thousands): +Assets held for sale: +Inventory +$ +28,620 +Unbilled accounts receivable +6,587 +Prepaid expenses and other current assets +324 +Property and equipment, net +8,793 +Reserve to reduce disposal group to fair value less costs to sell +(1,900 +) +Total assets held for sale +$ +42,424 +3. +Acquisitions +On October 9, 2007, the Company acquired three recently +refurbished SCR electric land-based drilling rigs and spare +drilling equipment for $29.0 million. The transaction was +accounted for as an acquisition of assets and the purchase price +was allocated among the assets acquired based on their estimated +fair market values. +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2009 and 2008 (in thousands): +2009 +2008 +Equipment +$ +3,230,737 +$ +2,897,431 +Oil and natural gas properties +93,354 +89,809 +Buildings +56,563 +61,529 +Land +9,795 +10,196 +3,390,449 +3,058,965 +Less accumulated depreciation and depletion +(1,280,047 +) +(1,121,853 +) +Property and equipment, net +$ +2,110,402 +$ +1,937,112 +F-12 +Table of Contents +Depreciation, depletion and impairment — The +following table summarizes depreciation, depletion and +impairment expense related to property and equipment for 2009, +2008 and 2007 (in millions): +2009 +2008 +2007 +Depreciation and impairment expense +$ +280.6 +$ +264.5 +$ +232.9 +Depletion expense +9.2 +11.5 +13.4 +Total +$ +289.8 +$ +276.0 +$ +246.3 +The Company evaluates the recoverability of its long-lived +assets whenever events or changes in circumstances indicate that +their carrying amounts may not be recoverable. In light of +adverse market conditions affecting the Company beginning in the +fourth quarter of 2008 and continuing into 2009, including a +substantial decrease in the operating levels of certain of its +business segments, a significant decline in oil and natural gas +commodity prices, and the results of the Company’s annual +goodwill impairment test at December 31, 2008 (see +Note 5), the Company deemed it necessary to assess the +recoverability of long-lived assets within its contract drilling +and drilling and completion fluids segments in 2008. Due to a +continued decrease in the operating levels in its contract +drilling business segment through the first three quarters of +2009, the Company again deemed it necessary to assess the +recoverability of long-lived assets within that segment during +2009. With respect to the long-lived assets in the +Company’s oil and natural gas exploration and production +segment, the Company assesses the recoverability of long-lived +assets at the end of each quarter due to revisions in its oil +and natural gas reserve estimates and expectations about future +commodity prices. The Company concluded that its pressure +pumping segment was not subject to the negative events and +trends, to the same degree as the contract drilling segment, and +thus did not require further assessment of recoverability. +The Company performs the first step of its impairment +assessments by comparing the undiscounted cash flows for each +long-lived asset or asset group to its respective carrying +value. Based on the results of these impairment tests, the +carrying amounts of long-lived assets in the contract drilling +and oil and natural gas segments were determined to be +recoverable, except as described below. +The Company’s analysis indicated that the carrying amounts +of certain oil and natural gas properties were not recoverable +at various testing dates in 2009, 2008 and 2007. The +Company’s estimates of expected future net cash flows from +impaired properties are used in measuring the fair value of such +properties. The Company recorded impairment charges of +$3.7 million, $4.4 million and $3.9 million in +2009, 2008 and 2007, respectively, related to its oil and +natural gas properties. The Company determined the fair value of +the impaired assets using internally developed unobservable +inputs (level 3 inputs in the fair value hierarchy of fair value +accounting). +During 2009 and 2008, in connection with its long term planning +process, the Company evaluated its then-current fleet of +marketable drilling rigs and identified 23 and 22 rigs, +respectively, that it determined would no longer be marketed as +rigs. Additionally, in 2009, the Company identified one rig +which would be recommissioned in a different configuration. The +components comprising these rigs were evaluated, and those +components with continuing utility to the Company’s other +marketed rigs were transferred to other rigs or to yards to be +used as spare equipment. The remaining components of these rigs +were impaired and the associated net book value of +$10.5 million in 2009 and $10.4 million in 2008 was +expensed in the Company’s consolidated statements of +operations as an impairment charge. The components that were +impaired were estimated to have no fair value. The Company +determined the fair value of the impaired assets using +internally developed unobservable inputs (level 3 inputs in the +fair value hierarchy of fair value accounting). +F-13 +Table of Contents +5. +Goodwill +Goodwill by operating segment as of December 31, 2009 and +2008 and changes for the years then ended are as follows (in +thousands): +2009 +2008 +Contract Drilling: +Balance as of January 1: +Goodwill +$ +86,234 +$ +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Changes to goodwill +— +— +Balance as of December 31: +Goodwill +86,234 +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Drilling and Completion Fluids (Discontinued Operations): +Balance as of January 1: +Goodwill +9,964 +9,964 +Accumulated impairment losses +(9,964 +) +— +— +9,964 +Impairment +— +(9,964 +) +Balance as of December 31: +Goodwill +9,964 +9,964 +Accumulated impairment losses +(9,964 +) +(9,964 +) +— +— +Total goodwill as of December 31 +$ +86,234 +$ +86,234 +Goodwill is evaluated at least annually to determine if the fair +value of recorded goodwill has decreased below its carrying +value. For purposes of impairment testing, goodwill is evaluated +at the reporting unit level. The Company’s reporting units +for impairment testing have been determined to be its operating +segments. Goodwill as of December 31, 2009 and 2008 is +recorded in the Company’s contract drilling segment. Prior +to 2008, goodwill was also recorded in the Company’s +drilling and completion fluids segment. +In connection with its annual goodwill impairment assessment +performed as of December 31, 2008, the Company performed an +impairment test of goodwill recorded in its contract drilling +and drilling and completion fluids reporting units. In light of +the adverse market conditions affecting the Company’s +common stock price beginning in the fourth quarter of 2008 and +continuing into 2009, including a significant decrease in the +number of its rigs operating and a significant decline in oil +and natural gas commodity prices, the Company utilized a +discounted cash flow methodology to estimate the fair values of +its reporting units. In completing its first step of the +analysis, the Company used a three-year projection of discounted +cash flows, plus a terminal value determined using the constant +growth method to estimate the fair value of its reporting units. +In developing these fair value estimates, the Company applied +key assumptions, including an assumed discount rate of 13.99% +for all reporting units, an assumed long-term growth rate of +3.50% for the contract drilling reporting unit and an assumed +long-term growth rate of 2.00% for the drilling and completion +fluids reporting unit. +Based on the results of the first step of the impairment test in +2008, the Company concluded that no impairment was indicated in +its contract drilling reporting unit as the estimated fair value +of that reporting unit exceeded its carrying value. An +impairment was indicated in the drilling and completion fluids +reporting unit as the estimated fair value of that reporting +unit was less than its carrying value. In validating this +conclusion, the Company considered the results of its long-lived +asset impairment tests and performed sensitivity analyses of the +key assumptions used in deriving the respective fair values of +its reporting units. The Company then performed the second step +of the analysis of its drilling and completion fluids reporting +unit, which included allocating the +F-14 +Table of Contents +estimated fair value to the identifiable tangible and intangible +assets and liabilities of this reporting unit based on their +respective values. This allocation indicated that there was no +residual value for goodwill, and accordingly the Company +recorded an impairment charge of $9.964 million in the year +ended December 31, 2008. As discussed in Note 2, the +Company exited the drilling and completion fluids business on +January 20, 2010, and the impairment charge recorded in +2008 is included in the loss from discontinued operations in the +Company’s statement of operations for the year ended +December 31, 2008. +The Company again performed its annual goodwill impairment +assessment as of December 31, 2009 related to the remaining +$86.2 million in goodwill recorded in its contract drilling +reporting unit. In completing its first step of the analysis, +the Company used a three-year projection of discounted cash +flows, plus a terminal value determined using the constant +growth method to estimate the fair value of the reporting unit. +In developing this fair value estimate, the Company applied key +assumptions, including an assumed discount rate of 15.42% and an +assumed long-term growth rate of 3.50%. Based on the results of +the first step of the impairment test in 2009, the Company +concluded that no impairment was indicated in its contract +drilling reporting unit as the estimated fair value of that +reporting unit exceeded its carrying value. +In the event that market conditions weaken, the Company may be +required to record an impairment of goodwill in its contract +drilling reporting unit in the future, and such impairment could +be material. +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2009 and 2008 (in thousands): +2009 +2008 +Salaries, wages, payroll taxes and benefits +$ +14,744 +$ +30,334 +Workers’ compensation liability +66,015 +70,439 +Sales, use and other taxes +10,975 +12,105 +Insurance, other than workers’ compensation +11,261 +14,209 +Other +6,613 +5,658 +$ +109,608 +$ +132,655 +7. +Asset +Retirement Obligation +The Company records a liability for the estimated costs to be +incurred in connection with the abandonment of oil and natural +gas properties in the future. This liability is included in the +caption “other liabilities” on the consolidated +balance sheet. The following table describes the changes to the +Company’s asset retirement obligations during 2009 and 2008 +(in thousands): +2009 +2008 +Balance at beginning of year +$ +3,047 +$ +1,593 +Liabilities incurred +157 +516 +Liabilities settled +(354 +) +(424 +) +Accretion expense +118 +59 +Revision in estimated costs of plugging oil and natural gas wells +(13 +) +1,303 +Asset retirement obligation at end of year +$ +2,955 +$ +3,047 +8. +Borrowings +Under Revolving Credit Facility +In March 2009, the Company entered into an unsecured revolving +credit facility with a maximum borrowing capacity of +$240 million, including a letter of credit sublimit of +$150 million and a swing line sublimit of $40 million. +In addition, the aggregate borrowing and letter of credit +capacity under the revolving credit facility may, subject to the +terms and conditions set forth therein including the receipt of +additional commitments from lenders, be increased up to a +maximum amount not to exceed $450 million. +F-15 +Table of Contents +Interest is paid on the outstanding principal amount of +revolving credit facility borrowings at a floating rate based +on, at the Company’s election, LIBOR or a base rate. The +margin on LIBOR loans ranges from 3.00% to 4.00% and the margin +on base rate loans ranges from 2.00% to 3.00%, based on the +Company’s debt to capitalization ratio. At +December 31, 2009, the margin on LIBOR loans would have +been 3.00% and the margin on base rate loans would have been +2.00%. Any outstanding borrowings must be repaid at maturity on +January 31, 2012 and letters of credit may remain in effect +up to six months after such maturity date. This revolving credit +facility includes various fees, including a commitment fee on +the actual daily unused commitment (the commitment fee rate was +1.00% at December 31, 2009). +The Company incurred line of credit issuance costs of +approximately $6.2 million during 2009 in connection with +the revolving credit facility. These costs are being amortized +to interest expense over the contractual term of the revolving +credit facility. +There are customary representations, warranties, restrictions +and covenants associated with the revolving credit facility. +Financial covenants provide for a maximum debt to capitalization +ratio and a minimum interest coverage ratio. As of +December 31, 2009, the maximum debt to capitalization ratio +was 35% and the minimum interest coverage ratio was 3.00 to 1. +The Company does not expect that the restrictions and covenants +will impact its ability to operate or react to opportunities +that might arise. +As of December 31, 2009, the Company had no borrowings +outstanding under the revolving credit facility. The Company had +$46.3 million in letters of credit outstanding at +December 31, 2009 and, as a result, had available borrowing +capacity of approximately $194 million at that date. Each +domestic subsidiary of the Company has unconditionally +guaranteed the existing and future obligations of the Company +and each other guarantor under the revolving credit facility and +related loan documents, as well as obligations of the Company +and its subsidiaries under any interest rate swap contracts that +may be entered into with lenders party to the revolving credit +facility. +9. +Commitments, +Contingencies and Other Matters +Commitments — As of December 31, 2009, the +Company maintained letters of credit in the aggregate amount of +$46.3 million for the benefit of various insurance +companies as collateral for retrospective premiums and retained +losses which could become payable under the terms of the +underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically +renewed. As of December 31, 2009, no amounts had been drawn +under the letters of credit. +As of December 31, 2009, the Company had commitments to +purchase approximately $186 million of major equipment. +Contingencies — The Company’s contract +services operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in +personal injury or death, suspended drilling operations, damage +to, or destruction of equipment, damage to producing formations +and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains +general liability insurance coverage of $1.0 million per +occurrence in excess of a $1.0 million self-insured +retention for a total limit of $2.0 million per occurrence, +with $10.0 million of aggregate coverage and excess +liability and umbrella coverages up to $200 million per +occurrence and in the aggregate. The Company maintains a +$1.0 million per occurrence deductible on its workers’ +compensation, general liability and automobile liability +insurance coverages. Accrued expenses related to insurance +claims are set forth in Note 6. +The Company believes it is adequately insured for bodily injury +and property damage to others with respect to its operations. +However, such insurance may not be sufficient to protect the +Company against liability for all consequences of personal +injury, well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its rigs. However, it does not +cover the full replacement cost of the rigs and the Company does +not carry insurance against loss of earnings resulting from such +damage. There can be no assurance that such insurance coverage +will always be available on terms that are satisfactory to the +Company, if at all. +F-16 +Table of Contents +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic twelve +month renewals unless the Company notifies the Key Employee at +least ninety days before the end of such renewal period that the +term will not be extended. If a change in control of the Company +occurs during the term of the agreement and the Key +Employee’s employment is terminated (i) by the Company +other than for cause or other than automatically as a result of +death, disability or retirement, or (ii) by the Key +Employee for good reason (as those terms are defined in the +Change in Control Agreements), then the Key Employee shall +generally be entitled to, among other things: +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +10. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2007, 2008 +and 2009 as follows: +Per Share +Total +(in thousands) +2007: +Paid on March 30, 2007 +$ +0.08 +$ +12,527 +Paid on June 29, 2007 +0.12 +18,860 +Paid on September 28, 2007 +0.12 +18,690 +Paid on December 28, 2007 +0.12 +18,484 +Total cash dividends +$ +0.44 +$ +68,561 +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +F-17 +Table of Contents +Per Share +Total +(in thousands) +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +On February 10, 2010, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.05 per share to be paid on March 30, 2010 to holders of +record as of March 15, 2010. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors +approved a stock buyback program authorizing purchases of up to +$250 million of the Company’s common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2007, the Company purchased +3,308,850 shares of its common stock under the program at a +cost of approximately $70.4 million. During the year ended +December 31, 2008, the Company purchased +3,502,047 shares of its common stock under the program at a +cost of approximately $66.3 million. During the year ended +December 31, 2009, the Company purchased 5,715 shares +of its common stock under the program at a cost of approximately +$79,000. As of December 31, 2009, the Company is authorized +to purchase approximately $113 million of the +Company’s outstanding common stock under the program. +Shares purchased under the program are accounted for as treasury +stock. +Additionally, the Company purchased 114,983, 152,235 and +20,269 shares of treasury stock from employees during 2009, +2008 and 2007, respectively. These shares were purchased at fair +market value upon the vesting of restricted stock to provide the +employees with the funds necessary to satisfy payroll tax +withholding obligations. The total purchase price for these +shares was approximately $1.5 million, $4.5 million +and $496,000 in 2009, 2008 and 2007, respectively. These +purchases were made pursuant to the terms of the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to +the stock buyback program. +11. +Stock-based +Compensation +The Company uses share-based payments to compensate employees +and non-employee directors. The Company recognizes the cost of +share-based payments under the fair-value-based method. Prior to +2009, share-based awards consisted of equity instruments in the +form of stock options, restricted stock or restricted stock +units, with all such awards subject to service conditions and, +in certain cases, performance conditions. Beginning in 2009, +share-based awards also include cash-settled performance unit +awards which are accounted for as liability awards. The Company +issues shares of common stock when vested stock options are +exercised, when restricted stock is granted and when restricted +stock units vest. +The Company’s shareholders have approved the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 +Plan”), and the Board of Directors adopted a resolution +that no future grants would be made under any of the +Company’s other previously existing plans. During 2008, the +Company amended the 2005 Plan to, among other +F-18 +Table of Contents +things, increase the total number of shares authorized for grant +from 6,250,000 to 10,250,000. The Company’s share-based +compensation plans at December 31, 2009 follow: +Shares +Shares +Authorized +Awards +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended +10,250,000 +4,980,068 +2,545,524 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +2,860,634 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +214,136 +— +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (“1996 Plan”) +— +35,000 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over one year for non-employee +directors and 3 to 4 years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2009, only +non-incentive stock options, restricted stock awards, restricted +stock units and performance unit awards had been granted under +the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Options granted under the 1996 Plan typically vest over two or +five years as dictated by the Compensation Committee. These +options have terms of no more than 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. +Stock Options — The Company estimates the grant +date fair values of stock options using the Black-Scholes-Merton +valuation model (“Black-Scholes”). Volatility +assumptions are based on the historic volatility of the +Company’s common stock over the most recent period equal to +the expected term of the options as of the date the options are +granted. The expected term assumptions are based on the +Company’s experience with respect to employee stock option +activity. Dividend yield assumptions are based on the expected +dividends at the time the options are granted. The risk-free +interest rate assumptions are determined by reference to United +States Treasury +F-19 +Table of Contents +yields. Weighted-average assumptions used to estimate grant date +fair values for stock options granted in the years ended +December 31, 2009, 2008 and 2007 follow: +2009 +2008 +2007 +Volatility +49.90 +% +37.04 +% +36.37 +% +Expected term (in years) +4.00 +4.17 +4.00 +Dividend yield +1.67 +% +2.27 +% +1.97 +% +Risk-free interest rate +1.67 +% +2.91 +% +4.55 +% +Stock option activity for the year ended December 31, 2009 +follows: +Weighted-average +Shares +exercise price +Outstanding at beginning of year +5,933,572 +$ +21.20 +Granted +1,037,500 +$ +13.12 +Exercised +(82,802 +) +$ +6.87 +Expired +(46,500 +) +$ +18.76 +Outstanding at end of year +6,841,770 +$ +20.17 +Exercisable at end of year +5,258,103 +$ +21.18 +Options outstanding at December 31, 2009 have an aggregate +intrinsic value of approximately $4.7 million and a +weighted-average remaining contractual term of 6.0 years. +Options exercisable at December 31, 2009 have an aggregate +intrinsic value of approximately $1.9 million and a +weighted-average remaining contractual term of 5.1 years. +Additional information with respect to options granted, vested +and exercised during the years ended December 31, 2009, +2008 and 2007 follows: +2009 +2008 +2007 +Weighted-average grant-date fair value of stock options granted +(per share) +$ +4.71 +$ +7.20 +$ +7.09 +Grant-date fair value of stock options vested during the year +(in thousands) +$ +6,973 +$ +6,761 +$ +5,613 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +510 +$ +45,240 +$ +3,186 +As of December 31, 2009, options to purchase +1,583,667 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2009 with respect +to these non-vested options that are expected to vest follows: +Aggregate intrinsic value +$2.7 million +Weighted-average remaining contractual term +8.95 years +Weighted-average remaining expected term +3.03 years +Weighted-average remaining vesting period +1.98 years +Unrecognized compensation cost +$7.1 million +Restricted Stock — For all restricted stock +awards to date, shares of common stock were issued when the +awards were made. Non-vested shares are subject to forfeiture +for failure to fulfill service conditions and, in certain cases, +performance conditions. Non-forfeitable dividends are paid on +non-vested shares of restricted stock. For restricted stock +awards made prior to 2008, the Company uses the +“graded-vesting” attribution method to recognize +periodic compensation cost over the vesting period. For +restricted stock awards made in 2008 and thereafter, the Company +uses the straight-line method to recognize periodic compensation +cost over the vesting period. +F-20 +Table of Contents +Restricted stock activity for the year ended December 31, +2009 follows: +Weighted- +average +Grant Date +Shares +Fair Value +Non-vested restricted stock outstanding at beginning of year +1,429,571 +$ +28.49 +Granted +603,600 +$ +13.75 +Vested +(745,715 +) +$ +27.97 +Forfeited +(55,555 +) +$ +26.65 +Non-vested restricted stock outstanding at end of year +1,231,901 +$ +21.67 +As of December 31, 2009, approximately +1,145,000 shares of non-vested restricted stock outstanding +are expected to vest. Additional information as of +December 31, 2009 with respect to these unvested shares +follows: +Aggregate intrinsic value +$ +17.6 million +Weighted-average remaining vesting period +1.54 years +Unrecognized compensation cost +$ +13.9 million +Restricted Stock Units — For all restricted +stock unit awards made to date, shares of common stock are not +issued until the units vest. Restricted stock units are subject +to forfeiture for failure to fulfill service conditions. +Non-forfeitable cash dividend equivalents are paid on non-vested +restricted stock units. +Restricted stock unit activity for the year ended +December 31, 2009 follows: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock units outstanding at beginning of +year +17,500 +$ +31.60 +Granted +6,500 +$ +14.39 +Vested +(5,833 +) +$ +31.60 +Forfeited +(2,000 +) +$ +14.39 +Non-vested restricted stock units outstanding at end of year +16,167 +$ +26.81 +Performance Unit Awards. On April 28, +2009, the Company granted performance unit awards to certain +executive officers (the “2009 Performance Units”). The +2009 Performance Units provide for those executive officers to +receive a cash payment upon the achievement of certain +performance goals established by the Company during a specified +period. The performance period for the 2009 Performance Units is +the period from April 1, 2009 through March 31, 2012. +The performance goals for the 2009 Performance Units are tied to +the Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee. These goals are +considered to be market conditions under the relevant accounting +standards. Generally, the recipients will receive a base payment +if the Company’s total shareholder return is positive and, +when compared to the peer group, is at or above the 25th +percentile but less than the 50th percentile; two times the base +if at or above the 50th percentile but less than the 75th +percentile, and four times the base if at the 75th percentile or +higher. The total base amount with respect to the 2009 +Performance Units is approximately $1.7 million. As the +2009 Performance Units are to be settled in cash at the end of +the performance period, the Company’s pro-rated obligation +is measured at estimated fair value at the end of each reporting +period and as of December 31, 2009 this pro-rated +obligation was approximately $859,000. +Dividends on Equity Awards — Non-forfeitable +cash dividends and dividend equivalents paid on equity awards +are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of restricted stock awards expected to vest. +F-21 +Table of Contents +• +Dividends are recognized as additional compensation cost for the +portion of restricted stock awards that are not expected to vest +or that ultimately do not vest. +• +Dividend equivalents are recognized as additional compensation +cost for restricted stock units. +12. +Leases +The Company incurred rent expense of $11.9 million, +$31.5 million and $27.6 million for the years 2009, +2008 and 2007, respectively. Rent expense is primarily related +to short-term equipment rentals that are passed through to +customers. The Company’s obligations under non-cancelable +operating lease agreements are not material to the +Company’s operations or cash flows. +13. +Income +Taxes +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2009, 2008 and 2007 are as follows (in +thousands): +2009 +2008 +2007 +Federal income tax expense (benefit): +Current +$ +(117,493 +) +$ +117,367 +$ +169,634 +Deferred +103,574 +57,879 +36,911 +(13,919 +) +175,246 +206,545 +State income tax expense (benefit): +Current +(1,883 +) +6,475 +16,174 +Deferred +(1,875 +7,070 +987 +(3,758 +) +13,545 +17,161 +Foreign income tax expense (benefit): +Current +338 +4,256 +5,220 +Deferred +(256 +) +443 +424 +82 +4,699 +5,644 +Total income tax expense (benefit): +Current +(119,038 +) +128,098 +191,028 +Deferred +101,443 +65,392 +38,322 +Total income tax expense (benefit) +$ +(17,595 +) +$ +193,490 +$ +229,350 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2009, 2008 and 2007 is summarized as follows: +2009 +2008 +2007 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +4.7 +1.7 +1.4 +Permanent differences +(5.7 +) +(1.2 +) +(1.6 +) +Other, net +0.1 +(0.2 +) +(0.3 +) +Effective tax rate +34.1 +% +35.3 +% +34.5 +% +F-22 +Table of Contents +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +December 31, +2009 +Change +2008 +Change +2007 +Change +2006 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +— +$ +— +$ +— +$ +(374 +) +$ +374 +$ +(1,496 +) +$ +1,870 +Workers’ compensation allowance +24,624 +(1,360 +) +25,984 +(602 +) +26,586 +223 +26,363 +Embezzlement costs +773 +45 +728 +68 +660 +(13,634 +) +14,294 +Other +18,843 +(2,780 +) +21,623 +3,219 +18,404 +3,903 +14,501 +44,240 +(4,095 +) +48,335 +2,311 +46,024 +(11,004 +) +57,028 +Non-current: +Net operating loss carryforwards +4,872 +4,872 +— +— +— +(374 +) +374 +AMT credit +— +— +— +(118 +) +118 +— +118 +Expense associated with employee stock options +9,129 +2,500 +6,629 +1,381 +5,248 +2,186 +3,062 +Federal benefit of foreign deferred tax liabilities +9,160 +(256 +) +9,416 +443 +8,973 +424 +8,549 +Federal benefit of state deferred tax liabilities +9,772 +2,702 +7,070 +1,643 +5,427 +735 +4,692 +Other +9,485 +4,120 +5,365 +614 +4,751 +704 +4,047 +42,418 +13,938 +28,480 +3,963 +24,517 +3,675 +20,842 +Total deferred tax assets +86,658 +9,843 +76,815 +6,274 +70,541 +(7,329 +) +77,870 +Deferred tax liabilities: +Current: +Other +(11,363 +) +1,044 +(12,407 +) +(1,753 +) +(10,654 +) +(2,493 +) +(8,161 +) +Non-current: +Property and equipment basis difference +(413,113 +) +(110,786 +) +(302,327 +) +(70,362 +) +(231,965 +) +(28,465 +) +(203,500 +) +Other +(10,961 +) +(7,091 +) +(3,870 +) +8,172 +(12,042 +) +(6,741 +) +(5,301 +) +(424,074 +) +(117,877 +) +(306,197 +) +(62,190 +) +(244,007 +) +(35,206 +) +(208,801 +) +Total deferred tax liabilities +(435,437 +) +(116,833 +) +(318,604 +) +(63,943 +) +(254,661 +) +(37,699 +) +(216,962 +) +Net deferred tax liability +$ +(348,779 +) +$ +(106,990 +) +$ +(241,789 +) +$ +(57,669 +) +$ +(184,120 +) +$ +(45,028 +) +$ +(139,092 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2009 and +2008 to be realized as a result of the reversal of existing +taxable temporary differences giving rise to deferred tax +liabilities and the generation of taxable income; therefore, no +valuation allowance is necessary. +Other deferred tax assets consist primarily of the tax effect of +various allowance accounts and tax-deferred expenses expected to +generate future tax benefit of approximately $28 million. +Other deferred tax liabilities consist +F-23 +Table of Contents +primarily of the tax effect of receivables from insurance +companies and tax-deferred income not yet recognized for tax +purposes. +For income tax purposes, the Company generated approximately +$450 million of Federal and state net operating losses +during the year ended December 31, 2009. Of this amount, +approximately $378 million will be carried back to prior +years, and the remaining balance can be carried forward to +future years. The net operating losses that can be carried +forward, if unused, are scheduled to expire as follows: +2014 — $7 million; 2019 — +$15 million and 2029 — $50 million. +The Company adopted a new accounting standard on January 1, +2007 which clarified the accounting for uncertainty in income +taxes recognized in an enterprise’s financial statements +and prescribed a recognition threshold and measurement attribute +for the financial statement recognition and measurement of a tax +position taken or expected to be taken in a tax return. As a +result of the adoption of this standard in 2007, the Company +reduced a reserve for an uncertain tax position related to a +prior business combination that had originally been recorded as +goodwill (see Note 5). The impact of adjustments to +reserves with respect to other uncertain tax positions was not +material. As of December 31, 2009, the Company had no +unrecognized tax benefits. The Company has established a policy +to account for interest and penalties related to uncertain +income tax positions as operating expenses. As of +December 31, 2009, the tax years ended December 31, +2006 through December 31, 2008 are open for examination by +U.S. taxing authorities. As of December 31, 2009, the +tax years ended December 31, 2005 through December 31, +2008 are open for examination by Canadian taxing authorities. +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $2.8 million in 2009, $4.5 million in +2008 and $4.0 million in 2007 for the Company’s cash +contributions to the plan. +15. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to three business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services and (iii) the +investment, on a working interest basis, in oil and natural gas +properties. Each of these segments represents a distinct type of +business. These segments have separate management teams which +report to the Company’s chief operating decision maker. The +results of operations in these segments are regularly reviewed +by the chief operating decision maker for purposes of +determining resource allocation and assessing performance. As +discussed in Note 2, the Company exited the drilling and +completion fluids services business which previously was +reported as a business segment in January 2010. Operating +results for that business for the years ended December 31, +2009, 2008 and 2007 are presented as discontinued operations in +the consolidated statements of operations. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2009, the Company +had 341 marketable land-based drilling rigs, of which 73 of the +drilling rigs were based in west Texas and southeastern New +Mexico; 100 in north central and east Texas, northern Louisiana +and Mississippi; 56 in the Rocky Mountain region (Colorado, +Utah, Wyoming, Montana and North Dakota); 49 in south Texas; 28 +in the Texas panhandle, Oklahoma and Arkansas; 20 in western +Canada; and 15 in the Appalachian Basin. +For the years ended December 31, 2009, 2008 and 2007, +contract drilling revenue earned in Canada was +$45.4 million, $88.5 million and $72.9 million, +respectively. Additionally, we had long-lived assets within our +contract drilling segment located in Canada of +$69.2 million and $67.2 million as of +December 31, 2009 and 2008, respectively. +Pressure Pumping — The Company provides +pressure pumping services primarily in the Appalachian Basin. +Pressure pumping services consist primarily of well stimulation +and cementing for the completion of new wells and remedial work +on existing wells. Well stimulation involves processes inside a +well designed to enhance the flow of oil, natural gas, or other +desired substances from the well. Cementing is the process of +inserting material between the hole and the pipe to center and +stabilize the pipe in the hole. +F-24 +Table of Contents +Oil and Natural Gas — The Company has been +engaged in the development, exploration, acquisition and +production of oil and natural gas. Through October 31, +2007, the Company served as operator with respect to several +properties and was actively involved in the development, +exploration, acquisition and production of oil and natural gas. +Effective November 1, 2007 the Company sold the related +operations portion of its exploration and production business. +The Company continues to own and invest in oil and natural gas +assets as a working interest owner. The Company’s oil and +natural gas interests are located primarily in Texas and New +Mexico. +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Revenues: +Contract drilling +$ +600,423 +$ +1,808,600 +$ +1,744,884 +Pressure pumping +161,441 +217,494 +202,812 +Oil and natural gas +21,218 +42,360 +41,637 +Total segment revenues +783,082 +2,068,454 +1,989,333 +Elimination of intercompany revenues(a) +(1,136 +) +(4,574 +) +(3,237 +) +Total revenues +$ +781,946 +$ +2,063,880 +$ +1,986,096 +Income (loss) from continuing operations before income taxes: +Contract drilling +$ +(11,219 +) +$ +520,636 +$ +558,792 +Pressure pumping +1,017 +42,019 +64,257 +Oil and natural gas +950 +13,711 +10,998 +(9,252 +) +576,366 +634,047 +Corporate and other +(35,577 +) +(34,596 +) +(31,124 +) +Embezzlement recoveries(b) +— +— +43,955 +Net (loss) gain on asset disposals(c) +(3,385 +) +4,163 +16,432 +Interest income +381 +1,553 +2,351 +Interest expense +(4,148 +) +(630 +) +(2,187 +) +Other +426 +502 +363 +Income (loss) from continuing operations before income taxes +$ +(51,555 +) +$ +547,358 +$ +663,837 +Identifiable assets: +Contract drilling +$ +2,129,567 +$ +2,255,421 +$ +2,132,910 +Pressure pumping +213,094 +210,805 +154,120 +Oil and natural gas +25,355 +31,760 +37,885 +Corporate and other(d) +294,136 +214,831 +140,284 +Total assets +$ +2,662,152 +$ +2,712,817 +$ +2,465,199 +Depreciation, depletion and impairment: +Contract drilling +$ +248,424 +$ +239,700 +$ +213,812 +Pressure pumping +27,589 +19,600 +14,311 +Oil and natural gas +12,927 +15,856 +17,410 +Corporate and other +907 +834 +813 +Total depreciation, depletion and impairment +$ +289,847 +$ +275,990 +$ +246,346 +F-25 +Table of Contents +Years Ended December 31, +2009 +2008 +2007 +Capital expenditures: +Contract drilling +$ +395,376 +$ +360,645 +$ +539,506 +Pressure pumping +43,144 +61,289 +47,582 +Oil and natural gas +7,341 +22,981 +17,516 +Corporate and other +6,785 +511 +— +Total capital expenditures +$ +452,646 +$ +445,426 +$ +604,604 +(a) +Includes contract drilling intercompany revenues related to +drilling services provided for wells in which the Company owns a +working interest. +(b) +The Company’s former CFO has pleaded guilty to criminal +charges and has been sentenced and is serving a term of +imprisonment arising out of his embezzlement of funds from the +Company prior to his termination in 2005. The net embezzlement +recovery in 2007 includes the recognition of the recovery of +assets seized by a court appointed receiver, net of related +professional fees. +(c) +Net gains or losses associated with the disposal of assets +relate to corporate strategy decisions of the executive +management group. Accordingly, the related gains or losses have +been separately presented and excluded from the results of +specific segments. +(d) +Corporate and other assets primarily include identifiable assets +associated with the Company’s former drilling and +completion fluids segment as well as cash on hand managed by the +parent corporation and certain deferred Federal income tax +assets. +16. +Concentrations +of Credit Risk +Financial instruments, which potentially subject the Company to +concentrations of credit risk, consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial +institutions. At December 31, 2009 and 2008, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2009 +2008 +Deposits in FDIC and SIPC-insured institutions under insurance +limits +$ +20,543 +$ +588 +Deposits in FDIC and SIPC-insured institutions over insurance +limits +47,376 +79,387 +Deposits in foreign banks +4,383 +18,805 +72,302 +98,780 +Less outstanding checks and other reconciling items +(22,425 +) +(17,557 +) +Cash and cash equivalents +$ +49,877 +$ +81,223 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2009, 2008, or 2007. The Company recognized +bad debt expense for 2009, 2008 and 2007 of $3.8 million, +$4.4 million and $2.9 million, respectively. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +F-26 +Table of Contents +17. +Related +Party Transactions +Joint Operation of Oil and Natural Gas +Properties — Through October 31, 2007, the +Company served as operator with respect to several properties +and was actively involved in the development, exploration, +acquisition and production of oil and natural gas. Effective +November 1, 2007, the Company sold the operations portion +of its exploration and production business. The Company +continues to own and invest in oil and natural gas assets as a +working interest owner. During the time that the Company served +as operator, it served as operator with respect to certain oil +and natural gas properties in which certain of its affiliated +persons have participated, either individually or through +entities they control. These participations were typically +through working interests in prospects or properties originated +or acquired by Patterson Petroleum LLC, a wholly owned +subsidiary of Patterson-UTI Energy, Inc. +During the time that the Company served as operator, sales of +working interests to affiliated parties were made by the Company +at its cost, comprised of the Company’s costs of acquiring +and preparing the working interests for sale plus a promote fee +in some cases. These costs were paid by the working interest +owners on a pro rata basis based upon their working interest +ownership percentage. The price at which working interests were +sold to affiliated persons was the same price at which working +interests were sold to unaffiliated persons except that in some +cases the affiliated persons also paid a promote fee. The +affiliated persons received oil and natural gas production +revenue (net of royalty) of $19.0 million from these +properties in 2007. These persons or entities in turn paid for +joint operating costs (including drilling and other development +expenses) of $9.2 million incurred in 2007. +18. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2008 +Operating revenues +$ +472,004 +$ +487,538 +$ +572,798 +$ +531,540 +Operating income +119,191 +122,364 +166,126 +138,252 +Income from continuing operations, net of income taxes +76,354 +75,184 +110,047 +92,282 +Income (loss) from discontinued operations, net of income taxes +1,055 +6,238 +(1,301 +) +(12,790 +) +Net income +77,409 +81,422 +108,746 +79,492 +Basic income (loss) per common share: +From continuing operations +$ +0.50 +$ +0.48 +$ +0.71 +$ +0.60 +From discontinued operations +$ +0.01 +$ +0.04 +$ +(0.01 +) +$ +(0.08 +) +Net income +$ +0.51 +$ +0.52 +$ +0.70 +$ +0.52 +Diluted income (loss) per common share: +From continuing operations +$ +0.49 +$ +0.48 +$ +0.70 +$ +0.60 +From discontinued operations +$ +0.01 +$ +0.04 +$ +(0.01 +) +$ +(0.08 +) +Net income +$ +0.50 +$ +0.52 +$ +0.69 +$ +0.52 +F-27 +Table of Contents +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2009 +Operating revenues +$ +268,209 +$ +140,497 +$ +159,671 +$ +213,569 +Operating income (loss) +25,154 +(25,855 +) +(24,619 +) +(22,894 +) +Income (loss) from continuing operations, net of income taxes +15,835 +(16,891 +) +(16,814 +) +(16,090 +) +Income (loss) from discontinued operations, net of income taxes +368 +(852 +) +(1,766 +) +(2,080 +) +Net income (loss) +16,203 +(17,743 +) +(18,580 +) +(18,170 +) +Basic income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income (loss) +$ +0.10 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +Diluted income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income (loss) +$ +0.10 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +As discussed in Note 2, the Company exited the drilling and +completion fluids services business in January 2010. The results +of operations related to the drilling and completion fluids +operating segment have been reclassified and presented as +discontinued operations in the quarterly financial information +above. +F-28 +Table of Contents +Schedule of Valuation and Qualifying Accounts Disclosure +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND QUALIFYING +ACCOUNTS +Charged to +Beginning +Costs and +Ending +Description +Balance +Expenses +Deductions(1) +Balance +(In thousands) +Year Ended December 31, 2009 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +9,330 +$ +4,700 +$ +3,119 +$ +10,911 +Year Ended December 31, 2008 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,014 +$ +4,350 +$ +5,034 +$ +9,330 +Year Ended December 31, 2007 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +7,484 +$ +2,550 +$ +20 +$ +10,014 +(1) +Uncollectible accounts written off net of recoveries. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 19, 2010 +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 +February 19, 2010. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +Table of Contents +EXHIBIT INDEX +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned by REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee +Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 +to Post-Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60466) +and incorporated herein by reference).* +10 +.6 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.8 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.9 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time.* +10 +.10 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.11 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.12 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +Table of Contents +10 +.13 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.14 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.15 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.16 +Severance Agreement between Patterson-UTI Energy, Inc. and +Douglas J. Wall, effective as of August 31, 2007 (filed +September 4, 2007 as Exhibit 10.3 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.17 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.19 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.20 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.21 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +Credit Agreement dated March 20, 2009, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer, swing line lender +and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC +Bank USA, N.A., as lender, Bank of America, N.A., as syndication +agent, letter of credit issuer and lender, and The Bank of +Tokyo-Mitsubishi UFJ, Ltd. as documentation agent and lender +(filed March 25, 2009 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.24 +Commitment Increase and Joinder Agreement dated June 19, +2009, among the Company, as borrower, Regions Bank as the new +lender, Bank of America, N.A. as a letter of credit issuer and +Wells Fargo Bank, N.A., as administrative agent, letter of +credit issuer, swing line lender and lender (filed August 4, +2009 as Exhibit 10.2 to the Company’s Quarterly Report on +Form 10-Q +and incorporated herein by reference). +10 +.25 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +Table of Contents +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2009, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Operations, (iii) the Consolidated Statements +of Changes in Stockholders’ Equity, (iv) the +Consolidated Statements of Cash Flows, (v) Notes to +Consolidated Financial Statements, tagged as blocks of text, and +(vi) Valuation and Qualifying Accounts. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/rp_note.txt b/raw/filings/0000889900/2009/0000950123-10-014515/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2009/0000950123-10-014515/rpt_disclosure.txt b/raw/filings/0000889900/2009/0000950123-10-014515/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..0e6851cd667aa20e0cf6c450eb5fde982b0c9eb1 --- /dev/null +++ b/raw/filings/0000889900/2009/0000950123-10-014515/rpt_disclosure.txt @@ -0,0 +1,24 @@ +related person transaction are considered, including whether +such transaction is in, or not inconsistent with, the best +interest of Patterson-UTI and whether, in appropriate cases, +such transaction is on commercial terms at least as favorable to +Patterson-UTI as would otherwise be available to or from an +unrelated third party or to Patterson-UTI’s employees +generally. Related person transactions generally include +transactions in an amount that exceeds $50,000 between +Patterson-UTI or any of its subsidiaries and an executive +officer, a director (or nominee to become director), an +immediate family member of any of the foregoing or any entity in +which any of the foregoing has a 10% or greater beneficial +ownership interest or in which they are an executive officer, +general partner, principal or engaged in a similar position. +Certain related person transactions have been pre-approved under +the terms of the policy, including, subject to certain +exceptions and limitations, the sale to or purchase from +Patterson-UTI of goods and services by entities related to +directors in the ordinary course of business that are immaterial +to Patterson-UTI and with respect to which the director has no +direct economic interest or decision making authority. +33 +Table of Contents +SECURITY \ No newline at end of file diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/filing.txt b/raw/filings/0000889900/2010/0000950123-11-013816/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e8f0a9c62db13b267db01d39a11101d36a7c236b --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/filing.txt @@ -0,0 +1,8788 @@ +10-K +1 +d78488e10vk.htm +FORM 10-K +e10vk +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. +20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2010 +or +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE +SECURITIES EXCHANGE ACT OF 1934 +For the transition period +from to +Commission File Number 0-22664 +Patterson-UTI Energy, +Inc. +(Exact name of registrant as +specified in its charter) +Delaware +(State or other jurisdiction +of +incorporation or organization) +75-2504748 +(I.R.S. Employer +Identification No.) +450 Gears Road, Suite 500, Houston, Texas +(Address of principal +executive offices) +77067 +(Zip +Code) +Registrant’s telephone number, including area code: +(281) 765-7100 +Securities Registered Pursuant to Section 12(b) of the +Act: +Title of Each Class +Name of Exchange on Which Registered +Common Stock, $0.01 Par Value +The Nasdaq Global Select Market +Preferred Share Purchase Rights +The Nasdaq Global Select Market +Securities +Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known +seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes þ or +No +o +Indicate by check mark if the registrant is not required to file +reports pursuant to Section 13 or Section 15(d) of the +Act. Yes o or +No +þ +Indicate by check mark whether the registrant (1) has filed +all reports required to be filed by Section 13 or 15(d) of +the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant +was required to file such reports), and (2) has been +subject to such filing requirements for the past +90 days. Yes þ No o +Indicate by check mark whether the registrant has submitted +electronically and posted on its corporate Website, if any, +every Interactive Data File required to be submitted and posted +pursuant to Rule 405 of +Regulation S-T +during the preceding 12 months (or for such shorter period +that the registrant was required to submit and post such +files). Yes þ or +No +o +Indicate by check mark if disclosure of delinquent filers +pursuant to Item 405 of +Regulation S-K +is not contained herein, and will not be contained, to the best +of registrant’s knowledge, in definitive proxy or +information statements incorporated by reference in +Part III of this +Form 10-K +or any amendment to this +Form 10-K. þ +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, a non-accelerated +filer, or a smaller reporting company. See the definitions of +“large accelerated filer,” “accelerated +filer” and “smaller reporting company” in Rule +12b-2 of the +Exchange Act. (Check one): +Large +accelerated +filer þ +Accelerated +filer o +Non-accelerated +filer o +Smaller +reporting +company o +(Do not check if a smaller reporting company) +Indicate by check mark whether the registrant is a shell company +(as defined in +Rule 12b-2 +of the +Act). Yes o No þ +The aggregate market value of the voting and non-voting common +equity held by non-affiliates of the registrant as of +June 30, 2010, the last business day of the +registrant’s most recently completed second fiscal quarter, +was $1,948,746,558, calculated by reference to the closing price +of $12.87 for the common stock on the Nasdaq Global Select +Market on that date. +As of February 11, 2011, the registrant had outstanding +154,203,597 shares of common stock, $.01 par value, +its only class of common stock. +Documents incorporated by reference: +Portions of the registrant’s definitive proxy statement for +the 2011 Annual Meeting of Stockholders are incorporated by +reference into Part III of this report. +DISCLOSURE +REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on +Form 10-K +(this “Report”) and other public filings and press +releases by us contain “forward-looking statements” +within the meaning of the Securities Act of 1933, as amended +(the “Securities Act”), the Securities Exchange Act of +1934, as amended (the “Exchange Act”), and the Private +Securities Litigation Reform Act of 1995, as amended. These +“forward-looking statements” involve risk and +uncertainty. These forward-looking statements include, without +limitation, statements relating to: liquidity; financing of +operations; continued volatility of oil and natural gas prices; +source and sufficiency of funds required for building new +equipment and additional acquisitions (if further opportunities +arise); impact of inflation; demand for our services; and other +matters. Our forward-looking statements can be identified by the +fact that they do not relate strictly to historic or current +facts and often use words such as “believes,” +“budgeted,” “continue,” “expects,” +“estimates,” “project,” “will,” +“could,” “may,” “plans,” +“intends,” “strategy,” or +“anticipates,” or the negative thereof and other words +and expressions of similar meaning. The forward-looking +statements are based on certain assumptions and analyses we make +in light of our experience and our perception of historical +trends, current conditions, expected future developments and +other factors we believe are appropriate in the circumstances. +Although we believe that the expectations reflected in such +forward-looking statements are reasonable, we can give no +assurance that such expectations will prove to have been +correct. Forward-looking statements may be made orally or in +writing, including, but not limited to, Management’s +Discussion and Analysis of Financial Condition and Results of +Operations included in this Report and other sections of our +filings with the United States Securities and Exchange +Commission (the “SEC”) under the Exchange Act and the +Securities Act. +Forward-looking statements are not guarantees of future +performance and a variety of factors could cause actual results +to differ materially from the anticipated or expected results +expressed in or suggested by these forward-looking statements. +Factors that might cause or contribute to such differences +include, but are not limited to, deterioration of global +economic conditions, declines in oil and natural gas prices that +could adversely affect demand for our services and their +associated effect on rates, utilization, margins and planned +capital expenditures, excess availability of land drilling rigs +and pressure pumping equipment, including as a result of +reactivation or construction, adverse industry conditions, +adverse credit and equity market conditions, difficulty in +integrating acquisitions, shortages of equipment and materials, +governmental regulation and ability to retain management and +field personnel. Refer to “Risk Factors” contained in +Part 1 of this Report for a more complete discussion of +these and other factors that might affect our performance and +financial results. You are cautioned not to place undue reliance +on any of our forward-looking statements. These forward-looking +statements are intended to relay our expectations about the +future, and speak only as of the date they are made. We +undertake no obligation to publicly update or revise any +forward-looking statement, whether as a result of new +information, changes in internal estimates or otherwise. +PART I +Item 1. +Business +Available +Information +This Report, along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Exchange Act, are available +free of charge through our Internet website +( www.patenergy.com ) as soon as reasonably practicable +after we electronically file such material with, or furnish it +to, the SEC. The information contained on our website is not +part of this Report or other filings that we make with the SEC. +You may read and copy any materials we file with the SEC at the +SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the +operation of the Public Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site ( www.sec.gov ) that +contains reports, proxy and information statements and other +information regarding issuers that file electronically with the +SEC. +1 +Overview +We own and operate one of the largest fleets of land-based +drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, +Utah, Wyoming, Montana, North Dakota, Pennsylvania, West +Virginia and western Canada. +As of December 31, 2010, we had a drilling fleet that +consisted of 356 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drill pipe and drilling rig components. +We provide pressure pumping services to oil and natural gas +operators primarily in Texas and the Appalachian Basin. Pressure +pumping services consist primarily of well stimulation and +cementing for completion of new wells and remedial work on +existing wells. We also own and invest in oil and natural gas +assets as a working interest owner. Our oil and natural gas +working interests are located primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We sold our drilling and +completion fluids services business on January 20, 2010. +On October 1, 2010 we acquired the assets and operations of +a pressure pumping business and an electric wireline business. +The electric wireline business that we acquired was classified +as held for sale at December 31, 2010 and sold on +January 27, 2011. The results of our drilling and +completion fluids services business and our electric wireline +business are presented as discontinued operations in this Report. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to three industry segments: +• +contract drilling services, +• +pressure pumping services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2010 and +2008. In 2009, our pressure pumping services and oil and natural +gas exploration and production segments had operating profits +and our contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2010, we had 356 marketable land-based +drilling rigs based in the following regions: +• +73 in west Texas and southeastern New Mexico, +• +97 in north central and east Texas, northern Louisiana and +Mississippi, +• +58 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana and North Dakota), +• +51 in south Texas and southern Louisiana, +• +32 in the Texas panhandle, Oklahoma and Arkansas, +• +25 in the Appalachian Basin, and +• +20 in western Canada. +2 +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 25,000 feet. +Of these drilling rigs, 124 are electric rigs and 232 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. We also have a substantial inventory of drill pipe and +drilling rig components, which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.4 billion during the last three years on capital +expenditures to (1) build new land drilling rigs, and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2010, 2009 and 2008, we spent approximately +$656 million, $395 million and $361 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the specifications of the +rig selected for a particular job. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well +basis or a term basis. +Well-to-well +contracts are generally short-term in nature and cover the +drilling of a single well or a series of wells. Term contracts +are entered into for a specified period of time (frequently one +to three years) and provide for the use of the drilling rig to +drill multiple wells. During 2010, our average number of days to +drill a well (which includes moving to the drill site, rigging +up and rigging down) was approximately 21 days. +Our 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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. Generally, we +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. +Generally, the customers indemnify us against claims that might +arise from other surface and subsurface pollution. Each drilling +contract contains the actual terms setting forth our rights and +obligations and those of the customer, any of which rights and +obligations may deviate from what is customary due to industry +conditions or other factors. +Our drilling 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 job 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. +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. Except for two wells drilled under footage +contracts in 2009, all of the wells we drilled in 2010, 2009 and +2008 were under daywork contracts. +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the +agreed-upon +depth. If we drill the well in less time than estimated, we have +the opportunity to improve our profits over those that would be +attainable under a daywork contract. Profits are reduced and +losses may be incurred if the well requires more days to drill +to the contracted depth than estimated. Footage contracts +generally contain greater risks for a drilling contractor than +daywork contracts. Under footage contracts, the drilling +contractor typically assumes +3 +certain risks associated with loss of the well from fire, +blowouts and other risks. We drilled two wells under footage +contracts in 2009, and we did not drill any wells under footage +contracts in 2010 or 2008. +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed- upon scope +of the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey +contracts in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2010 +2009 +2008 +Average rigs operating per day(1) +168 +91 +254 +Number of rigs operated during the year +220 +243 +315 +Number of wells drilled during the year +2,919 +1,539 +4,218 +Number of operating days(2) +61,244 +33,394 +93,068 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +(2) +Includes standby days under term contracts where revenue was +earned but the rig was not working. The number of these standby +days under term contracts was zero in 2010, 2,070 in 2009 and +486 in 2008. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2010 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +59 +9 +68 +12,000 to 15,999 +193 +8 +201 +16,000 to 25,000 +84 +— +84 +Totals +336 +20 +356 +At December 31, 2010, we owned and operated 317 trucks and +402 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and generally +enhances the efficiency of our contract drilling operations, +particularly in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, Oklahoma, +Wyoming, Utah, Pennsylvania and western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in Texas and the +Appalachian Basin. Pressure pumping services consist of well +stimulation and cementing for the completion of new wells and +remedial work on existing wells. Wells drilled in shale +formations and other unconventional plays require +4 +well stimulation through fracturing to allow the flow of oil and +natural gas. This is accomplished by pumping fluids under +pressure into the well bore to fracture the formation. Many +wells in conventional plays also receive well stimulation +services. The cementing process inserts material between the +wall of the well bore and the casing to support and stabilize +the casing. +Equipment — Our pressure pumping equipment at +December 31, 2010 includes equipment used in providing +hydraulic and nitrogen fracturing services as well as nitrogen, +cementing and acid pumping services as follows: +Quintiplex +Triplex +Other +Fracturing +Fracturing +Pumping +Equipment +Equipment +Equipment +Total +Number of Units +101 +90 +130 +321 +Approximate Hydraulic Horsepower +226,750 +126,850 +81,600 +435,200 +Our pressure pumping operations are supported by a fleet of +equipment including blenders, tractors, manifold trailers and +numerous trailers for transportation of materials to and from +the worksite as well as bins for storage of materials at the +worksite. +Oil and +Natural Gas Interests +We own and invest in oil and natural gas assets as a working +interest owner. Our oil and natural gas working interests are +located primarily in producing regions of Texas and New Mexico. +Customers +The customers of each of our contract drilling and pressure +pumping business segments are oil and natural gas operators. Our +customer base includes both major and independent oil and +natural gas operators. During 2010, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly +competitive. Historically, available equipment used in these +businesses has frequently exceeded demand in our markets. The +price for our services is a key competitive factor in our +markets, in part because equipment used in our businesses can be +moved from one area to another in response to market conditions. +In addition to price, we believe availability and condition of +equipment, quality of personnel, service quality and safety +record are key factors in determining which contractor is +awarded a job in the markets in which we operate. We expect that +the market for land drilling and pressure pumping services will +continue to be highly competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, +• +use of underground injection wells, and +• +hydraulic fracturing and related activities. +To date, applicable environmental laws and regulations in the +United States and Canada have not required the expenditure of +significant resources outside the ordinary course of business. +We do not anticipate any material capital expenditures for +environmental control facilities or extraordinary expenditures +to comply with +5 +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production, and otherwise have an +adverse effect on our operations. Federal, state, foreign and +local environmental laws and regulations currently apply to our +operations and may become more stringent in the future. Any +suspension or moratorium of the services we provide, whether or +not short-term in nature, by a Federal, state, foreign or local +governmental authority, could have a material adverse effect on +our business, financial condition and results of operation. +We believe 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 operated by us or our +predecessors, which may have resulted, or may result, in soil +and groundwater contamination in certain locations. Any +contamination found on, under or originating from the properties +may be subject to remediation requirements under Federal, state, +foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or +operators. In addition, it is possible we could be held +responsible for oil and natural gas properties in which we own +an interest but are not the operator. +Some of the environmental laws and regulations that are +applicable to our business operations are discussed in the +following paragraphs, but the discussion does not cover all +environmental laws and regulations that govern our operations. +In the United States, the Federal Comprehensive Environmental +Response Compensation and Liability Act of 1980, as amended, +commonly known as CERCLA, and comparable state statutes impose +strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may +subject a responsible party, such as us, to civil or criminal +actions. Although the liability for owners and operators is the +same +6 +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 activities include the performance of hydraulic fracturing +services to enhance the production of oil and natural gas from +formations with low permeability, such as shales. Due to +concerns raised relating to potential impacts of hydraulic +fracturing on groundwater quality, legislative and regulatory +efforts at the Federal level and in some states have been +initiated to render permitting and compliance requirements more +stringent for hydraulic fracturing or prohibit the activity +altogether. Such efforts could have an adverse effect on oil and +natural gas production activities, which in turn could have an +adverse effect on the hydraulic fracturing services that we +render for our exploration and production customers. +In Canada, a variety of Canadian federal, provincial and +municipal laws and regulations impose, among other things, +restrictions, liabilities and obligations in connection with the +generation, handling, use, storage, transportation, treatment +and disposal of hazardous substances and wastes and in +connection with spills, releases and emissions of various +substances to the environment. These laws and regulations also +require that facility sites and other properties associated with +our operations be operated, maintained, abandoned and reclaimed +to the satisfaction of applicable regulatory authorities. In +addition, new projects or changes to existing projects may +require the submission and approval of environmental assessments +or permit applications. These laws and regulations are subject +to frequent change, and the clear trend is to place increasingly +stringent limitations on activities that may affect the +environment. +Our operations are also subject to Federal, state, foreign and +local laws, rules and regulations for the control of air +emissions, including the Federal Clean Air Act and the Canadian +Environmental Protection Act. We are aware of the increasing +focus of local, state, national and international regulatory +bodies on greenhouse gas (GHG) emissions and climate change +issues. We are also aware of legislation proposed by United +States lawmakers and the Canadian legislature to reduce GHG +emissions, as well as GHG emissions regulations enacted by the +U.S. Environmental Protection Agency and the Canadian +provinces of Alberta and British Columbia. We will continue to +monitor and assess any new policies, legislation or regulations +in the areas where we operate to determine the impact of GHG +emissions and climate change on our operations and take +appropriate actions, where necessary. Any direct and indirect +costs of meeting these requirements may adversely affect our +business, results of operations and financial condition. +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, +• +fires, and +• +explosions. +These and other 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, including through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +7 +We maintain insurance coverage of types and amounts that we +believe to be customary in the industry, but we are not fully +insured against all risks, either because insurance is not +available or because of the high premium costs. Such risks +include personal injury, well disasters, extensive fire damage, +damage to the environment, and other hazards. The insurance +coverage that we maintain includes insurance for fire, windstorm +and other risks of physical loss to our rigs and other assets, +employer’s liability, automobile liability, commercial +general liability insurance, and workers compensation insurance. +We cannot assure, however, that any insurance obtained by us +will be adequate to cover any losses or liabilities, or that +this insurance will continue to be available or available on +terms that are acceptable to us. While we carry insurance to +cover physical damage to, or loss of, our drilling rigs and +other assets, such insurance does not cover the full replacement +cost of the rigs or other assets, and we do not carry insurance +against loss of earnings resulting from such damage. Liabilities +for which we are not insured, or which exceed the policy limits +of our applicable insurance, could have a material adverse +effect on our financial condition and results of operations. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +There is no assurance that we will obtain such contractual +indemnity, and if obtained, whether such indemnity will be +enforceable, whether the customer will be able to satisfy such +indemnity or whether such indemnity will be supported by +adequate insurance maintained by the customer. +Employees +We had approximately 7,000 full-time employees at +December 31, 2010. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada and, to a +lesser extent, our pressure pumping operations in the +Appalachian Basin, are subject to slow periods of activity +during the annual Spring thaw. +Raw +Materials and Subcontractors +We use many suppliers of raw materials and services. Although, +these materials and services have historically been available, +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. +Item 1A. +Risk +Factors. +You should consider each of the following factors as well as the +other information in this Report in evaluating our business and +our prospects. Additional risks and uncertainties not presently +known to us or that we currently consider immaterial may also +impair our business operations. If any of the following risks +actually occur, our business and financial results could be +harmed. You should also refer to the other information set forth +in this Report, including our financial statements and the +related notes. +Global +Economic Conditions May Adversely Affect Our Operating +Results. +Beginning in late 2008 and continuing through 2009, there was a +substantial deterioration in the global economic environment. As +part of this deterioration, there was substantial uncertainty in +the capital markets and access to financing was reduced. Due to +these conditions, our customers reduced or curtailed their +drilling programs, which resulted in a decrease in demand for +our services. Furthermore, these factors resulted in certain of +our customers experiencing an inability to pay suppliers, +including us. Although the significant deterioration in the +global economic environment appeared to stabilize to some degree +during 2010, there is no assurance that the global economic +environment could not quickly deteriorate again due to one or +more factors. A return of the conditions causing a deterioration +in the global economic environment could have a material adverse +effect on our business, financial condition, cash flows and +results of operations. +8 +We are +Dependent on the Oil and Natural Gas Industry and Market Prices +for Oil and Natural Gas. Declines in Oil and Natural Gas Prices +Have Adversely Affected Our Operating Results. +Our revenue, profitability and cash flows are highly dependent +upon prevailing prices for natural gas and oil. For many years, +oil and natural gas prices and markets have been extremely +volatile. Prices are affected by: +• +market supply and demand, +• +international military, political and economic +conditions, and +• +the ability of the Organization of Petroleum Exporting +Countries, commonly known as OPEC, to set and maintain +production and price targets. +All of these factors are beyond our control. During 2008, the +monthly average market price of natural gas (monthly average +Henry Hub price as reported by the Energy Information +Administration) peaked in June at $13.06 per Mcf before rapidly +declining to an average of $5.99 per Mcf in December. In 2009, +the monthly average market price of natural gas declined further +to a low of $3.06 per Mcf in September. The monthly average +market price of natural gas has not recovered to levels +experienced during early 2008 and was $4.38 per Mcf in December +2010. This volatility and the extended declines in the market +price of natural gas resulted in our customers significantly +reducing their drilling activities beginning in the fourth +quarter of 2008, and drilling activities remained low through +2009 before increasing somewhat in 2010. The increase in 2010 +can be attributed partially to increased activity in oil rich +basins as a result of the growing development of unconventional +oil reservoirs and an improvement in the price of oil compared +to 2009. Although our average number of rigs operating increased +during 2010, it remains well below the number of our available +rigs. Construction of new land drilling rigs in the United +States during the last ten years has significantly contributed +to excess capacity. As a result of decreased drilling activity +and excess capacity, our average number of rigs operating has +declined significantly from historic highs. We expect oil and +natural gas prices to continue to be volatile and to affect our +financial condition, operations and ability to access sources of +capital. Low market prices for natural gas and oil would likely +result in low demand for our drilling rigs and pressure pumping +services and would adversely affect our operating results, +financial condition and cash flows. +A +General Excess of Operable Land Drilling Rigs, Increasing Rig +Specialization and Excess Pressure Pumping Equipment May +Adversely Affect Our Utilization and Profit +Margins. +The North American land drilling industry has experienced +periods of downturn in demand over the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins and, +at times, have sustained losses during the downturn periods. +In addition, unconventional resource plays have substantially +increased recently and some drilling rigs are not capable of +drilling these wells efficiently. Accordingly, the utilization +of some older technology drilling rigs may be hampered by their +lack of capability to successfully compete for this work. Other +ongoing factors which could continue to adversely affect +utilization rates and pricing, even in an environment of high +oil and natural gas prices and increased drilling activity, +include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new drilling rigs. +Construction of new drilling rigs increased significantly during +the last ten years. The addition of new drilling rigs to the +market and the recent decrease in demand has resulted in excess +capacity. Similarly, the substantial recent increase in +unconventional resource plays has led to higher demand for +pressure pumping services. As a result, we believe there has +been, and we expect there to continue to be, a significant +increase in the construction of new pressure pumping equipment. +The addition of new pressure pumping equipment, as well as any +general decline in demand for pressure pumping services, could +result in there being substantially more pressure pumping +equipment available than necessary to meet demand. If this were +to occur, providers of pressure pumping services will have +difficulty sustaining profit margins and may sustain losses +during downturn periods. We cannot predict either the +9 +future level of demand for our contract drilling or pressure +pumping services or future conditions in the oil and natural gas +contract drilling or pressure pumping businesses. +Shortages +of Drill Pipe, Replacement Parts, Other Equipment and Materials +Adversely Affect Our Operating Results. +During periods of increased demand for drilling and pressure +pumping services, the industry has experienced shortages of +drill pipe, replacement parts, other equipment and materials, +including proppants and gels for our pressure pumping +operations. These shortages can cause the price of these items +to increase significantly and require that orders for the items +be placed well in advance of expected use. In addition, any +interruption in supply due to vendor or other issues could +result in significant delays in delivery of equipment and +materials or prevent operations. These price increases and +delays in delivery may require us to increase capital and repair +expenditures and incur higher operating costs. Severe shortages +or delays in delivery could limit our ability to operate our +drilling rigs and pressure pumping equipment. +The +Oil Service Business Segments in Which We Operate Are Highly +Competitive with Excess Capacity, which Adversely Affects Our +Operating Results. +Our land drilling and pressure pumping businesses are highly +competitive. At 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 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. +Labor +Shortages and Rising Labor Costs Adversely Affect Our Operating +Results. +During periods of increasing demand for contract drilling and +pressure pumping services, the industry experiences shortages of +qualified personnel. During these periods, our ability to +attract and retain sufficient qualified personnel to market and +operate our drilling rigs and pressure pumping equipment is +adversely affected, which negatively impacts both our operations +and profitability. Operationally, it is more difficult to hire +qualified personnel, which adversely affects our ability to +mobilize inactive rigs and pressure pumping equipment in +response to the increased demand for such services. +Additionally, wage rates for drilling and pressure pumping +personnel are likely to increase during periods of increasing +demand, resulting in higher operating costs. +Growth +Through the Building of New Rigs and Pressure Pumping Equipment +and Rig and Other Acquisitions are Not Assured. +We have increased our drilling rig fleet and pressure pumping +horsepower in the past through mergers, acquisitions and new +construction. The land drilling and pressure pumping industries +have experienced significant consolidation, and there can be no +assurance that acquisition opportunities will be available in +the future. We are also likely to continue to face intense +competition from other companies for available acquisition +opportunities. In addition, because improved technology has +enhanced the ability to recover oil and natural gas, contract +drillers may continue to build new, high technology rigs and +providers of pressure pumping services may continue to build +new, high horsepower equipment. +There can be no assurance that we will: +• +have sufficient capital resources to complete additional +acquisitions or build new rigs or pressure pumping equipment, +10 +• +successfully integrate additional drilling rigs, pressure +pumping equipment or other assets, +• +effectively manage the growth and increased size of our +organization, drilling fleet and pressure pumping equipment, +• +successfully deploy idle, stacked or additional rigs and +pressure pumping equipment, +• +maintain the crews necessary to operate additional drilling rigs +and pressure pumping equipment, or +• +successfully improve our financial condition, results of +operations, business or prospects as a result of any completed +acquisition or the building of new drilling rigs and pressure +pumping equipment. +We may incur substantial indebtedness to finance future +acquisitions, build new drilling rigs or build new pressure +pumping equipment and also may issue equity, convertible or debt +securities in connection with any such acquisitions or building +program. Debt service requirements could represent a significant +burden on our results of operations and financial condition, and +the issuance of additional equity would be dilutive to existing +stockholders. Also, continued growth could strain our +management, operations, employees and other resources. +The +Nature of our Business Operations Presents Inherent Risks of +Loss that, if not Insured or Indemnified Against, Could +Adversely Affect Our Operating Results. +Our operations are subject to many hazards inherent in the +contract drilling and pressure pumping businesses, which in turn +could cause personal injury or death, work stoppage, or serious +damage to our equipment. Our operations could also cause +environmental and reservoir damages. We maintain insurance +coverage and have indemnification agreements with many of our +customers. However, there is no assurance that such insurance or +indemnification agreements would be enforceable or adequately +protect us against liability or losses from all consequences of +these hazards. Additionally, there can be no assurance that +insurance would be available to cover any or all of these risks, +or, even if available, that insurance premiums or other costs +would not rise significantly in the future, so as to make the +cost of such insurance prohibitive. It is possible that a +customer or insurer could fail or be unable to meet its +indemnification or insurance obligations, which could result in +a material loss. Moreover, we could suffer a material loss if we +were to become subject to an unexpected judgment against us for +which we are uninsured, for which indemnification is +unenforceable or otherwise not available or that is beyond the +amounts we reserved or anticipated incurring. Incurring a +liability for which we are not fully insured or indemnified +could materially affect our business, financial condition and +results of operations. +We have also elected in some cases to accept a greater amount of +risk through increased deductibles on certain insurance +policies. For example, we generally maintain a $1.0 million +per occurrence deductible on our workers’ compensation and +equipment insurance coverages and a $2.0 million per +occurrence self insured retention on our general liability +insurance coverage. +Difficulties +Integrating Our Recently Acquired Pressure Pumping Assets Could +Adversely Affect Our Operating Results. +We expect that our recently acquired pressure pumping assets +will complement and expand our business. Successfully +integrating the acquired business depends on our ability to +integrate the acquired assets and personnel and to maintain and +grow the acquired customer base. We may encounter challenges in +integrating the acquired business with our existing operations +and management. We may not be able to fully take advantage of +expected business opportunities, including successfully +developing new markets and retaining acquired customers. The +integration of the new business may place additional strain on +our management. In addition, the acquired business may not +achieve anticipated results. If the acquired business is not +successfully integrated, our operating results could be +adversely affected. +We are +Dependent Upon our Subsidiaries to Meet our Obligations Under +our Long Term Debt +We have borrowings outstanding under a term loan and our senior +notes. These obligations are guaranteed by each of our existing +subsidiaries other than immaterial subsidiaries. Our ability to +meet our interest and principal payment obligations depends in +large part on dividends paid to us by our subsidiaries. If our +subsidiaries do not +11 +generate sufficient cash flows to pay us dividends, we may be +unable to meet our interest and principal payment obligations. +Environmental +Laws and Regulations, Including Violations Thereof Could +Materially Adversely Affect Our Operating Results. +All of our operations and facilities are subject to numerous +Federal, state, foreign and local environmental laws, rules and +regulations, including, without limitation, laws concerning the +containment and disposal of hazardous substances, oil field +waste and other waste materials, the use of underground storage +tanks, and the use of underground injection wells. The cost of +compliance with these laws and regulations could be substantial. +A failure to comply with these requirements could expose us to +substantial civil and criminal penalties. In addition, +environmental laws and regulations in the United States and +Canada impose a variety of requirements 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 and pressure pumping equipment, we +may be deemed to be a responsible party under these laws and +regulations. +Potential +Legislation and Regulation Covering Hydraulic Fracturing +Could Increase Our Costs and Result in Operational +Delays. +Members of the U.S. Congress and the +U.S. Environmental Protection Agency (the “EPA”) +are reviewing more stringent regulation of hydraulic fracturing, +a technology employed by our pressure pumping business, which +involves the injection of water, sand and chemicals under +pressure into rock formations to stimulate oil and natural gas +production. Both the EPA and the U.S. Congress are studying +whether there is any link between hydraulic fracturing +activities and soil or ground water contamination. As part of +their respective studies, the House Subcommittee on Energy and +Environment and the EPA each sent requests to a number of +companies, including our company for information on their +hydraulic fracturing practices. We have responded to each of the +inquiries. In addition, legislation has been proposed in the +U.S. Congress to amend the federal Safe Drinking Water Act +to require the disclosure of chemicals used by the oil and gas +industry in the hydraulic fracturing process, which could make +it easier for third parties opposing the hydraulic fracturing +process to initiate legal proceedings based on allegations that +specific chemicals used in the fracturing process are impairing +ground water or causing other damage. These bills, if adopted, +could establish an additional level of regulation at the federal +or state level that could lead to operational delays or +increased operating costs and could result in additional +regulatory burdens that could make it more difficult to perform +hydraulic fracturing and increase our costs of compliance and +doing business. Certain states have adopted or are considering +similar disclosure legislation. Additional regulation could +increase the costs of conducting our business and could +materially reduce our business opportunities and revenues if our +customers decrease their levels of activity in response to such +regulation. +Legislation +and Regulation of Greenhouse Gases Could Adversely Affect our +Business +We are aware of the increasing focus of local, state, national +and international regulatory bodies on GHG emissions and climate +change issues. We are also aware of legislation proposed by +United States lawmakers and the Canadian legislature to reduce +GHG emissions, as well as GHG emissions regulations enacted by +the EPA and the Canadian provinces of Alberta and British +Columbia. In 2007, the U.S. Supreme Court in +Massachusetts, et al. v. Environmental Protection Agency +held that carbon dioxide, a GHG, may be regulated as an +“air pollutant” under the Clean Air Act, which could +result in future regulations even if the U.S. Congress does +not enact new legislation regarding such emissions. We will +continue to monitor and assess any new policies, legislation or +regulations in the areas where we operate to determine the +impact of GHG emissions and climate change on our operations and +take appropriate actions, where necessary. Any direct and +indirect costs of meeting these requirements may adversely +affect our business, results of operations and financial +condition. +Anti-takeover +Measures in Our Charter Documents and Under State Law Could +Discourage an Acquisition and Thereby Affect the Related +Purchase Price. +We are a Delaware corporation subject to the Delaware General +Corporation Law, including Section 203, an anti-takeover +law. We have also enacted certain anti-takeover measures, +including a stockholders’ rights plan. In +12 +addition, our Board of Directors has the authority to issue up +to one million shares of preferred stock and to determine the +price, rights (including voting rights), conversion ratios, +preferences and privileges of that stock without further vote or +action by the holders of the common stock. As a result of these +measures and others, potential acquirers might find it more +difficult or be discouraged from attempting to effect an +acquisition transaction with us. This may deprive holders of our +securities of certain opportunities to sell or otherwise dispose +of the securities at above-market prices pursuant to any such +transactions. +Item 1B. +Unresolved +Staff Comments. +None. +Item 2. +Properties +Our corporate headquarters comprises approximately +12,000 square feet of leased office space, and is located +at 450 Gears Road, Suite 500, Houston, Texas. Our telephone +number at that address is +(281) 765-7100. +Our primary administrative office is located in Snyder, Texas +and includes approximately 37,000 square feet of office and +storage space. +Contract Drilling Operations — Our drilling +services are supported by several offices and yard facilities +located throughout our areas of operations, including Texas, New +Mexico, Oklahoma, Colorado, Utah, Wyoming, Pennsylvania and +western Canada. +Pressure Pumping — Our pressure pumping +services are supported by several offices and yard facilities +located throughout our areas of operations including Texas, +Pennsylvania, Ohio, West Virginia, Kentucky, Tennessee and +Colorado. +Oil and Natural Gas Working Interests — Our +interests in oil and natural gas properties are primarily +located in Texas and New Mexico. +We own our administrative offices in Snyder, Texas, as well as +several of our other facilities. We also lease a number of +facilities, and we do not believe that any one of the leased +facilities is individually material to our operations. We +believe that our existing facilities are suitable and adequate +to meet our needs. +Item 3. +Legal +Proceedings. +We are party to various legal proceedings arising in the normal +course of our business. We do not believe that the outcome of +these proceedings, either individually or in the aggregate, will +have a material adverse effect on our results of operations, +cash flows or financial condition. +Item 4. +(Removed +and Reserved). +13 +PART II +Item 5. +Market +for Registrant’s Common Equity, Related Stockholder Matters +and Issuer Purchases of Equity Securities. +(a) +Market +Information +Our common stock, par value $0.01 per share, is publicly traded +on the Nasdaq Global Select Market and is quoted under the +symbol “PTEN.” Our common stock is included in the +S&P MidCap 400 Index and several other market indices. The +following table provides high and low sales prices of our common +stock for the periods indicated: +High +Low +2009: +First quarter +$ +13.50 +$ +7.49 +Second quarter +15.95 +8.56 +Third quarter +15.98 +11.38 +Fourth quarter +18.07 +14.20 +2010: +First quarter +$ +18.67 +$ +13.19 +Second quarter +16.15 +11.85 +Third quarter +17.42 +12.52 +Fourth quarter +22.67 +16.59 +(b) +Holders +As of February 11, 2011, there were approximately 1,500 holders +of record of our common stock. +(c) +Dividends +We paid cash dividends during the years ended December 31, +2009 and 2010 as follows: +Per Share +Total +(in thousands) +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +2010: +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +On February 2, 2011, our Board of Directors approved a cash +dividend on our common stock in the amount of $0.05 per share to +be paid on March 30, 2011 to holders of record as of +March 15, 2011. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +14 +(d) +Securities +Authorized for Issuance Under Equity Compensation +Plans +Equity compensation plan information as of December 31, +2010 follows: +Equity Compensation Plan Information +Number of +Number of +Securities +Securities to +Remaining Available +be Issued upon +for Future Issuance +Exercise of +Weighted-Average +under Equity +Outstanding +Exercise Price +Compensation Plans +Options, +of Outstanding +(Excluding Securities +Warrants and +Options, Warrants +Reflected in +Plan Category +Rights +and Rights +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved by security holders(1) +7,541,550 +$ +19.78 +5,763,314 +Equity compensation plans not approved by security holders(2) +168,552 +$ +10.23 +— +Total +7,710,102 +$ +19.58 +5,763,314 +(1) +The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended (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, officers +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. +(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 officers and directors. No Incentive Stock +Options could be awarded under the 2001 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. +15 +(e) +Performance +Graph +The following graph compares the cumulative stockholder return +of our common stock for the period from December 31, 2005 +through December 31, 2010, with the cumulative total return +of the Standard & Poors 500 Stock Index, the +Standard & Poors MidCap Index, the Oilfield Service +Index and a peer group determined by us. Our peer group consists +of BJ Services Company, Bronco Drilling Company, Inc., +Helmerich & Payne, Inc., Nabors Industries, Ltd., +Pioneer Drilling Co., Precision Drilling Corp and Superior Well +Services, Inc. All of the companies in our peer group are +providers of land-based drilling or pressure pumping services. +BJ Services Company and Superior Well Services, Inc. were +acquired by Baker Hughes, Inc. and Nabors Industries, Ltd., +respectively during 2010. The graph assumes investment of $100 +on December 31, 2005 and reinvestment of all dividends. +Fiscal Year Ended December 31, +2005 +2006 +2007 +2008 +2009 +2010 +Company/Index +($) +($) +($) +($) +($) +($) +Patterson-UTI Energy, Inc. +100.00 +71.28 +61.09 +37.17 +50.37 +71.56 +Peer Group Index +100.00 +79.68 +74.95 +36.97 +59.59 +76.24 +S&P 500 Stock Index +100.00 +115.79 +122.16 +76.96 +97.33 +111.99 +Oilfield Service Index (OSX) +100.00 +110.35 +167.21 +67.77 +109.89 +139.47 +S&P MidCap Index +100.00 +110.32 +119.12 +75.96 +104.36 +132.16 +The foregoing graph is based on historical data and is not +necessarily indicative of future performance. This graph shall +not be deemed to be “soliciting material” or to be +“filed” with the SEC or subject to Regulations 14A or +14C under the Exchange Act or to the liabilities of +Section 18 under such Act. +Item 6. +Selected +Financial Data. +Our selected consolidated financial data as of December 31, +2010, 2009, 2008, 2007 and 2006, and for each of the five years +in the period ended December 31, 2010 should be read in +conjunction with “Management’s Discussion and Analysis +of Financial Condition and Results of Operations” and the +Consolidated Financial Statements and related Notes thereto, +included as Items 7 and 8, respectively, of this Report. +Certain reclassifications have been made to the historical +financial data to conform with the 2010 presentation. Due to the +sale of our drilling and completion fluids business in January +2010 and the sale of our electric wireline business in January +16 +2011, the results of operations for those businesses have been +reclassified and are presented as discontinued operations in all +periods presented below. +Years Ended December 31, +2010 +2009 +2008 +2007 +2006 +(In thousands, except per share amounts) +Statement of Operations Data: +Operating revenues: +Contract drilling +$ +1,081,898 +$ +599,287 +$ +1,804,026 +$ +1,741,647 +$ +2,169,370 +Pressure pumping +350,608 +161,441 +217,494 +202,812 +145,671 +Oil and natural gas +30,425 +21,218 +42,360 +41,637 +39,187 +Total +1,462,931 +781,946 +2,063,880 +1,986,096 +2,354,228 +Operating costs and expenses: +Contract drilling +655,678 +357,742 +1,038,327 +963,150 +1,002,001 +Pressure pumping +235,100 +124,100 +147,377 +117,250 +85,529 +Oil and natural gas +7,020 +7,341 +12,793 +10,864 +13,374 +Depreciation, depletion, amortization and impairment +333,493 +289,847 +275,990 +246,346 +193,664 +Selling, general and administrative +53,042 +43,935 +43,273 +42,688 +36,770 +Net (gain) loss on asset disposals +(22,812 +) +3,385 +(4,163 +) +(16,432 +) +3,905 +Provision for bad debts +(2,000 +) +3,810 +4,350 +2,875 +5,585 +Embezzlement costs (recoveries) +— +— +— +(43,955 +) +3,081 +Acquisition-related expenses +2,485 +— +— +— +— +Total +1,262,006 +830,160 +1,517,947 +1,322,786 +1,343,909 +Operating income (loss) +200,925 +(48,214 +) +545,933 +663,310 +1,010,319 +Other income (expense) +(10,171 +) +(3,341 +) +1,425 +527 +4,657 +Income (loss) from continuing operations before income taxes +190,754 +(51,555 +) +547,358 +663,837 +1,014,976 +Income tax expense (benefit) +72,856 +(17,595 +) +193,490 +229,350 +360,639 +Income (loss) from continuing operations +$ +117,898 +$ +(33,960 +) +$ +353,868 +$ +434,487 +$ +654,337 +Income (loss) from continuing operations per common share: +Basic +$ +0.77 +$ +(0.22 +) +$ +2.29 +$ +2.78 +$ +3.94 +Diluted +$ +0.76 +$ +(0.22 +) +$ +2.27 +$ +2.75 +$ +3.89 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.60 +$ +0.44 +$ +0.28 +Weighted average number of common shares outstanding: +Basic +152,772 +152,069 +153,379 +154,755 +165,159 +Diluted +153,276 +152,069 +154,358 +156,612 +167,200 +Balance Sheet Data: +Total assets +$ +3,423,031 +$ +2,662,152 +$ +2,712,817 +$ +2,465,199 +$ +2,192,503 +Borrowings under line of credit +— +— +— +50,000 +120,000 +Long term debt (including current maturities) +398,750 +— +— +— +— +Stockholders’ equity +2,187,607 +2,081,700 +2,126,942 +1,896,030 +1,562,466 +Working capital +241,445 +263,511 +337,615 +226,209 +334,429 +17 +Item 7. +Management’s +Discussion and Analysis of Financial Condition and Results of +Operations +Management Overview — We are a leading provider +of contract services to the North American oil and natural gas +industry. Our services primarily involve the drilling, on a +contract basis, of land-based oil and natural gas wells and, to +a lesser extent, pressure pumping services. In addition to the +aforementioned contract services, we also invest, on a working +interest basis, in oil and natural gas properties. For the three +years ended December 31, 2010, our operating revenues +consisted of the following (dollars in thousands): +2010 +2009 +2008 +Contract drilling +$ +1,081,898 +74 +% +$ +599,287 +76 +% +$ +1,804,026 +87 +% +Pressure pumping +350,608 +24 +161,441 +21 +217,494 +11 +Oil and natural gas +30,425 +2 +21,218 +3 +42,360 +2 +$ +1,462,931 +100 +% +$ +781,946 +100 +% +$ +2,063,880 +100 +% +We provide our contract services to oil and natural gas +operators in many of the oil and natural gas producing regions +of North America. Our contract drilling operations are focused +in various regions of Texas, New Mexico, Oklahoma, Arkansas, +Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North +Dakota, Pennsylvania, West Virginia and western Canada, while +our pressure pumping services are focused primarily in Texas and +the Appalachian Basin. The oil and natural gas properties in +which we hold interests are primarily located in Texas and New +Mexico. +Generally, the profitability of our business is impacted most by +two primary factors in our contract drilling segment: our +average number of rigs operating and our average revenue per +operating day. During 2010, our average number of rigs operating +was 168 compared to 91 in 2009 and 254 in 2008. Our average +revenue per operating day was $17,670 in 2010 compared to +$17,950 in 2009 and $19,380 in 2008. We had consolidated net +income of $117 million for 2010 compared to a consolidated +net loss of $38.3 million for 2009. The increase in +consolidated net income was primarily due to our contract +drilling segment experiencing an increase in the average number +of rigs operating. Additionally, our pressure pumping segment +experienced an increase in large multi-stage fracturing jobs in +2010 compared to 2009. This increase includes the fourth quarter +contribution of a pressure pumping business we acquired on +October 1, 2010, which significantly expanded our pressure +pumping operations into new markets in the fourth quarter of +2010. +Our revenues, profitability and cash flows are highly dependent +upon prevailing prices for natural gas and oil. During periods +of improved commodity prices, the capital spending budgets of +oil and natural gas operators tend to expand, which generally +results in increased demand for our contract services. +Conversely, in periods when these commodity prices deteriorate, +the demand for our contract services generally weakens and we +experience downward pressure on pricing for our services. After +reaching a peak in June 2008, there was a significant decline in +oil and natural gas prices and a substantial deterioration in +the global economic environment. As part of this deterioration, +there was substantial uncertainty in the capital markets and +access to financing was reduced. Due to these conditions, our +customers reduced or curtailed their drilling programs, which +resulted in a decrease in demand for our services, as evidenced +by the decline in our monthly average number of rigs operating +from a high of 283 in October 2008 to a low of 60 in June 2009. +Our monthly average number of rigs operating has subsequently +increased from the mid-year low in 2009 to 196 in December 2010. +The decline in commodity prices and deterioration in the global +economy resulted in certain of our customers experiencing an +inability to pay suppliers, including us. We are also highly +impacted by competition, the availability of excess equipment, +labor issues and various other factors that could materially +adversely affect our business, financial condition, cash flows +and results of operations. Please see “Risk Factors” +in Item 1A of this Report. +We believe that our liquidity as of December 31, 2010, +which includes approximately $241 million in working +capital and approximately $359 million available under our +$400 million revolving credit facility, together with cash +expected to be generated from operations, should provide us with +sufficient ability to fund our current plans to build new +equipment, make improvements to our existing equipment and pay +cash dividends. If we pursue opportunities for growth that +require capital, we believe we would be able to satisfy these +needs through a combination of working capital, cash flows from +operating activities borrowing capacity under our revolving +18 +credit facility or additional debt or equity financing. However, +there can be no assurance that such capital will be available on +reasonable terms, if at all. +Commitments and Contingencies — As of +December 31, 2010, we maintained letters of credit in the +aggregate amount of $41.2 million for the benefit of +various insurance companies as collateral for retrospective +premiums and retained losses which could become payable under +the terms of the underlying insurance contracts. These letters +of credit expire annually at various times during the year and +are typically renewed. As of December 31, 2010, no amounts +had been drawn under the letters of credit. +As of December 31, 2010, we had commitments to purchase +approximately $267 million of major equipment. +Trading and investing — We have not engaged in +trading activities that include high-risk securities, such as +derivatives and non-exchange traded contracts. We invest cash +primarily in highly liquid, short-term investments such as +overnight deposits and money market accounts. +Description of business — We conduct our +contract drilling operations in Texas, New Mexico, Oklahoma, +Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, +Montana, North Dakota, Pennsylvania, West Virginia and western +Canada. For the years ended December 31, 2010, 2009 and +2008, revenue earned in Canada was $65.7 million, +$45.4 million and $88.5 million, respectively. +Additionally, we had long-lived assets located in Canada of +$70.7 million and $69.2 million as of +December 31, 2010 and 2009, respectively. As of +December 31, 2010, we had 356 marketable land-based +drilling rigs. We provide pressure pumping services to oil and +natural gas operators primarily in Texas and the Appalachian +Basin. Pressure pumping services are primarily well stimulation +and cementing for completion of new wells and remedial work on +existing wells. We also invest, on a working interest basis, in +oil and natural gas properties. +Critical +Accounting Policies +In addition to established accounting policies, our consolidated +financial statements are impacted by certain estimates and +assumptions made by management. The following is a discussion of +our critical accounting policies pertaining to property and +equipment, oil and natural gas properties, goodwill, revenue +recognition and the use of estimates. +Property and equipment — Property and +equipment, including betterments which extend the useful life of +the asset, are stated at cost. Maintenance and repairs are +charged to expense when incurred. We provide for the +depreciation of our property and equipment using the +straight-line method over the estimated useful lives. Our method +of depreciation does not change when equipment becomes idle; we +continue to depreciate idled equipment on a straight-line basis. +No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our +long-lived assets, including property and equipment, for +impairment whenever events or changes in circumstances indicate +that the carrying values of certain assets may not be recovered +over their estimated remaining useful lives. In connection with +this review, assets are grouped at the lowest level at which +identifiable cash flows are largely independent of other asset +groupings. The cyclical nature of our industry has resulted in +fluctuations in rig utilization over periods of time. Management +believes that the contract drilling industry will continue to be +cyclical and rig utilization will continue to fluctuate. Based +on management’s expectations of future trends, we estimate +future cash flows over the life of the respective assets in our +assessment of impairment. These estimates of cash flows are +based on historical cyclical trends in the industry as well as +management’s expectations regarding the continuation of +these trends in the future. Provisions for asset impairment are +charged against income when estimated future cash flows, on an +undiscounted basis, are less than the asset’s net book +value. Any provision for impairment is measured based on +discounted cash flows. +On a periodic basis, we evaluate our fleet of drilling rigs for +marketability. In connection with our long term planning +process, we evaluated our then-current fleet of marketable +drilling rigs in 2010, 2009 and 2008 and identified four, 23 and +22 rigs, respectively, that we determined would no longer be +marketed as rigs. The components comprising these rigs were +evaluated, and those components with continuing utility to our +other marketed rigs were transferred to other rigs or to our +yards to be used as spare equipment. The remaining components of +these rigs were impaired and the associated net book value of +$4.2 million in 2010, $10.5 million in 2009 and +$10.4 million in 2008 was expensed in our consolidated +statements of operations as an impairment charge. +19 +In late 2008, we experienced a significant decrease in the +number of our rigs operating and oil and natural gas prices +decreased significantly. These events were deemed by us to be +triggering events that required us to perform an assessment with +respect to impairment of long-lived assets, including property +and equipment, in our contract drilling segment. With respect to +these long-lived assets, we estimated future cash flows over the +expected life of the long-lived assets, which were comprised +primarily of property and equipment, and determined that, on an +undiscounted basis, expected cash flows exceeded the carrying +value of the long-lived assets. Based on this assessment, no +impairment was indicated in 2008. Due to a continued decrease in +the operating levels in our contract drilling segment through +the first three quarters of 2009, we again deemed it necessary +to perform an impairment assessment of long-lived assets in our +contract drilling segment in 2009. Based on the estimated +undiscounted cash flows associated with the assets, we +determined that no impairment was indicated in 2009. In light of +the recent favorable trends in rig utilization and revenue per +operating day experienced by us and our peers, we concluded that +no triggering event had occurred in 2010 with respect to our +contract drilling segment. We also concluded that no triggering +event had occurred with respect to our pressure pumping segment +in 2010, 2009 or 2008. Impairment considerations related to our +oil and natural gas segment are discussed below. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and economic viability of the +respective projects. If no progress has been made in assessing +the reserves and economic viability of a project after one year +following the completion of drilling, we consider the well costs +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 for each respective field. +We review our proved oil and natural gas properties for +impairment whenever a triggering event occurs, such as downward +revisions in reserve estimates or decreases in oil and natural +gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on our +expectation of future commodity prices over the lives of the +respective fields. These cash flow estimates are reviewed by an +independent petroleum engineer. If the net book value of a field +exceeds its undiscounted cash flow estimate, impairment expense +is measured and recognized as the difference between net book +value and discounted cash flow. The discounted cash flow +estimates used in measuring impairment are based on our +expectations of future commodity prices over the life of the +respective field. We review unproved oil and natural gas +properties quarterly to assess potential impairment. Our +impairment assessment is made on a +lease-by-lease +basis and considers factors such as our intent to drill, lease +terms and abandonment of an area. If an unproved property is +determined to be impaired, the related property costs are +expensed. Impairment expense related to proved and unproved oil +and natural gas properties totaled approximately $792,000, +$3.7 million and $4.4 million for the years ended +December 31, 2010, 2009 and 2008, respectively, and is +included in depreciation, depletion and impairment in the +accompanying consolidated statements of operations. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. We assess +impairment of our goodwill annually as of December 31, or +on an interim basis if events or circumstances indicate that the +fair value of goodwill may have decreased below its carrying +value. Goodwill impairment testing is performed at the level of +our reporting units. Our reporting units have been determined to +be the same as our operating segments. +In connection with our annual impairment assessment of goodwill, +we compare the fair value of the reporting unit with its +carrying value. If the fair value exceeds the carrying value, no +impairment is indicated. If the carrying value exceeds the fair +value, we measure any impairment of goodwill in that reporting +unit by allocating the fair value to the identifiable assets and +liabilities of the reporting unit based on their respective fair +values. Any excess +20 +unallocated fair value would equal the implied fair value of +goodwill, and if that amount is below the carrying value of +goodwill, an impairment charge is recognized. +In connection with our annual goodwill impairment assessment +performed as of December 31, 2008, we performed an +impairment test of goodwill recorded in our contract drilling +and drilling and completion fluids reporting units. In light of +the adverse market conditions affecting our common stock price +beginning in the fourth quarter of 2008 and continuing into +2009, including a significant decrease in the average number of +our rigs operating and a significant decline in oil and natural +gas commodity prices, we utilized a discounted cash flow +methodology to estimate the fair values of our reporting units. +In completing the first step of our analysis, we used a +three-year projection of discounted cash flows, plus a terminal +value determined using the constant growth method to estimate +the fair value of our reporting units. In developing these fair +value estimates, we applied key assumptions, including an +assumed discount rate of 13.99% for all reporting units, an +assumed long-term growth rate of 3.50% for the contract drilling +reporting unit and an assumed long-term growth rate of 2.00% for +the drilling and completion fluids reporting unit. +Based on the results of the first step of the impairment test in +2008, we concluded that no impairment was indicated in our +contract drilling reporting unit as the estimated fair value of +that reporting unit exceeded its carrying value. However, an +impairment was indicated in our drilling and completion fluids +reporting unit as the estimated fair value of that reporting +unit was less than its carrying value. In validating this +conclusion, we considered the results of our long-lived asset +impairment tests and performed sensitivity analyses of the key +assumptions used in deriving the respective fair values of our +reporting units. We then performed the second step of the +analysis of our drilling and completion fluids reporting unit, +which included allocating the estimated fair value to the +identifiable tangible and intangible assets and liabilities of +this reporting unit based on their respective values. This +allocation indicated no residual value for goodwill, and +accordingly we recorded an impairment charge of approximately +$10.0 million in our December 31, 2008 statement +of operations. We exited the drilling and completion fluids +business on January 20, 2010, and the 2008 impairment +charge is included in our loss from discontinued operations in +our statement of operations for the year ended December 31, +2008. +We performed our annual goodwill impairment assessment as of +December 31, 2009 related to the $86.2 million in +goodwill recorded in our contract drilling reporting unit. In +completing the first step of our analysis, we used a three-year +projection of discounted cash flows, plus a terminal value +determined using the constant growth method to estimate the fair +value of the reporting unit. In developing this fair value +estimate, we applied key assumptions, including an assumed +discount rate of 15.42% and an assumed long-term growth rate of +3.50%. Based on the results of the first step of the impairment +test in 2009, we concluded that no impairment was indicated in +our contract drilling reporting unit as the estimated fair value +of that reporting unit exceeded its carrying value. +We performed our annual goodwill impairment assessment as of +December 31, 2010. In completing the first step of our +analysis, we estimated our enterprise value based on our market +capitalization as determined by reference to the closing price +of our common stock during the fifteen days before and after +year end. We allocated the enterprise value to our reporting +units and determined that the fair values of our reporting units +were in excess of their carrying value. As a result, we +concluded that no impairment of goodwill was indicated as of +December 31, 2010. +During the fourth quarter of 2010, we recorded goodwill in our +pressure pumping reporting unit in connection with our +acquisition of a pressure pumping business. The goodwill +associated with this acquisition was estimated to be +$67.6 million. +In the event that market conditions weaken, we may be required +to record an impairment of goodwill in our contract drilling or +pressure pumping reporting units in the future, and such +impairment could be material. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed-contract method of accounting. 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 the risks therein, we follow the +completed-contract method of accounting for such arrangements. +21 +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 total +revenues. We recognize as revenue reimbursements received from +third parties for +out-of-pocket +expenses and account for those +out-of-pocket +expenses as direct costs. Except for two wells drilled under +footage contacts in 2009, all of the wells we drilled in 2010, +2009 and 2008 were drilled under daywork contracts. +Use of estimates — The preparation of financial +statements in conformity with accounting principles generally +accepted in the United States of America requires management to +make certain estimates and assumptions that affect the reported +amounts of assets and liabilities and disclosures of contingent +assets and liabilities at the date of the financial statements +and the reported amounts of revenues and expenses during the +reporting period. Actual results could differ from such +estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation and depletion, +• +fair values of assets acquired and liabilities assumed in +acquisitions, +• +goodwill and long-lived asset impairments, and +• +reserves for self-insured levels of insurance coverage. +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. +Liquidity +and Capital Resources +As of December 31, 2010, we had working capital of +$241 million, including cash and cash equivalents of +$27.6 million. During 2010, our sources of cash flow +included: +• +$526 million from operating activities, +• +$400 million in proceeds from long term debt, +• +$42.6 million in proceeds from the disposal of our drilling +and completion fluids business, and +• +$29.4 million in proceeds from the disposal of property and +equipment. +During 2010, we used $238 million to acquire pressure +pumping and electric wireline businesses, $30.8 million to +pay dividends on our common stock, $10.8 million to pay +debt issuance costs, $1.9 million to repurchase shares of +our common stock and $738 million: +• +to build new drilling rigs, +• +to make capital expenditures for the betterment and +refurbishment of our drilling rigs, +• +to acquire and procure drilling equipment and facilities to +support our drilling operations, +• +to fund capital expenditures for our pressure pumping +segment, and +• +to fund investments in oil and natural gas properties on a +working interest basis. +22 +We paid cash dividends during the year ended December 31, +2010 as follows: +Per Share +Total +(In thousands) +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +On February 2, 2011, our Board of Directors approved a cash +dividend on our common stock in the amount of $0.05 per share to +be paid on March 30, 2011 to holders of record as of +March 15, 2011. The amount and timing of all future +dividend payments, if any, is subject to the discretion of the +Board of Directors and will depend upon business conditions, +results of operations, financial condition, terms of our credit +facilities and other factors. +On August 1, 2007, our Board of Directors approved a stock +buyback program, authorizing purchases of up to +$250 million of our common stock in open market or +privately negotiated transactions. During the year ended +December 31, 2010, we purchased 8,743 shares of our +common stock under this program at a cost of approximately +$123,000. As of December 31, 2010, we are authorized to +purchase approximately $113 million of our outstanding +common stock under this program. +On August 19, 2010, we entered into a Credit Agreement (the +“2010 Credit Agreement”). The 2010 Credit Agreement is +a committed senior unsecured credit facility that includes a +revolving credit facility and a term loan facility. The 2010 +Credit Agreement replaced a previous unsecured revolving credit +facility. +The revolving credit facility permits aggregate borrowings of up +to $400 million and contains a letter of credit facility +that is limited to $150 million and a swing line facility +that is limited to $40 million. Subject to customary +conditions, we may request that the lenders’ aggregate +commitments with respect to the revolving credit facility be +increased by up to $100 million, not to exceed total +commitments of $500 million. The maturity date for the +revolving credit facility is August 19, 2013. +The term loan facility provided for a loan of $100 million +which was funded on August 19, 2010. The term loan facility +is payable in quarterly principal installments commencing +November 19, 2010, and the installment amounts vary from +1.25% of the original principal amount for each of the first +four quarterly installments, 2.50% of the original principal +amount for each of the subsequent eight quarterly installments, +5.00% of the original principal amount for the next subsequent +three quarterly installments, and the remainder due at maturity. +The maturity date for the term loan facility is August 19, +2014. +Loans under the 2010 Credit Agreement bear interest by +reference, at our election, to the LIBOR rate or base rate. The +applicable margin on LIBOR rate loans varies from 2.75% to 3.75% +and the applicable margin on base rate loans varies from 1.75% +to 2.75%, in each case determined based upon our debt to +capitalization ratio. As of December 31, 2010, the +applicable margin on LIBOR rate loans was 2.75% and the +applicable margin on base rate loans was 1.75%. A letter of +credit fee is payable by us equal to the applicable margin for +LIBOR rate loans times the daily amount available to be drawn +under outstanding letters of credit. The commitment fee payable +to the lenders for the unused portion of the revolving credit +facility varies from 0.50% to 0.75% based upon our debt to +capitalization ratio and was 0.50% as of December 31, 2010. +The 2010 Credit Agreement contains customary representations, +warranties, indemnities and affirmative and negative covenants. +The 2010 Credit Agreement also requires compliance with two +financial covenants. We must not permit our debt to +capitalization ratio to exceed 45% at any time. The 2010 Credit +Agreement generally defines the debt to capitalization ratio as +the ratio of (a) total borrowed money indebtedness to +(b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. We also must not +permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit +Agreement generally defines the interest coverage ratio as the +ratio of earnings before interest, taxes, depreciation and +amortization (“EBITDA”) of the four prior fiscal +quarters to interest charges for the same period. We were in +compliance with these financial covenants as of +December 31, +23 +2010. We do not expect that the restrictions and covenants will +impair our ability to operate or react to opportunities that +might arise. +As of December 31, 2010, we had $98.8 million +principal amount outstanding under the term loan facility at an +interest rate of 3.125% and no borrowings outstanding under the +revolving credit facility. We had $41.2 million in letters +of credit outstanding at December 31, 2010, and as a +result, we had available borrowing capacity of approximately +$359 million at that date. +On October 5, 2010, we completed the issuance and sale of +$300 million in aggregate principal amount of our 4.97% +Series A Senior Notes due October 5, 2020 (the +“Notes”) in a private placement. A portion of the +proceeds from the Notes was used to repay a $200 million +borrowing on our revolving credit facility, which had been drawn +to fund a portion of a business acquisition that closed on +October 1, 2010. +The Notes bear interest at a rate of 4.97% per annum and were +priced at 100% of the principal amount of the Notes. We will pay +interest on the Notes on April 5 and October 5 of each year +commencing on April 5, 2011. The Notes will mature on +October 5, 2020. The Notes are prepayable at our option, in +whole or in part, provided that in the case of a partial +prepayment, prepayment must be in an amount not less than 5% of +the aggregate principal amount of the Notes then outstanding, at +any time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment +date, plus a “make-whole” premium as specified in the +note purchase agreement. We must offer to prepay the Notes upon +the occurrence of any change of control. In addition, we must +offer to prepay the Notes upon the occurrence of certain asset +dispositions if the proceeds therefrom are not timely reinvested +in productive assets. If any offer to prepay is accepted, the +purchase price of each prepaid Note is 100% of the principal +amount thereof, plus accrued and unpaid interest thereon to the +prepayment date. +The note purchase agreement requires compliance with two +financial covenants. We must not permit our debt to +capitalization ratio to exceed 50% at any time. The note +purchase agreement generally defines the debt to capitalization +ratio as the ratio of (a) total borrowed money indebtedness +to (b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. We also must not +permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 2.50 to 1.00. The note purchase +agreement generally defines the interest coverage ratio as the +ratio for the four prior quarters of EBITDA to interest charges +for the same period. We were in compliance with these financial +covenants as of December 31, 2010. We do not expect that +the restrictions and covenants will impair our ability to +operate or react to opportunities that might arise. +Events of default under the note purchase agreement include +failure to pay principal or interest when due, failure to comply +with the financial and operational covenants, a cross default +event, a judgment in excess of a threshold event, the guaranty +agreement ceasing to be enforceable, the occurrence of certain +ERISA events, a change of control event and bankruptcy and other +insolvency events. If an event of default occurs and is +continuing, then holders of a majority in principal amount of +the Notes have the right to declare all the notes +then-outstanding to be immediately due and payable. In addition, +if we default in payments on any Note, then until such defaults +are cured, the holder thereof may declare all the Notes held by +it to be immediately due and payable. +We believe that our current level of cash, short-term +investments and borrowing capacity available under our revolving +credit facility, together with cash expected to be generated +from our operating activities, should be sufficient to fund our +current plans to build new equipment, make improvements to our +existing equipment and pay cash dividends. +From time to time, opportunities to expand our business, +including acquisitions and the building of new equipment, are +evaluated. The timing, size or success of any acquisition and +the associated capital commitments are unpredictable. If we +pursue opportunities for growth that require capital, we believe +we would be able to satisfy these needs through a combination of +working capital, cash generated from operations, borrowing +capacity under our revolving credit facility or additional debt +or equity financing. However, there can be no assurance that +such capital will be available on reasonable terms, if at all. +24 +Contractual +Obligations +The following table presents information with respect to our +contractual obligations as of December 31, 2010 (dollars in +thousands): +Payments due by period +Less Than 1 +More Than 5 +Total +Year +1-3 Years +3-5 Years +Years +Borrowings under revolving credit facility(1) +$ +— +$ +— +$ +— +$ +— +$ +— +Borrowings under term loan(2) +98,750 +6,250 +22,500 +70,000 +— +Interest on term loan(3) +9,371 +3,097 +5,267 +1,007 +— +Series A Senior Notes(4) +300,000 +— +— +— +300,000 +Interest on Series A Senior Notes(5) +145,546 +14,910 +29,820 +29,820 +70,996 +Commitments to purchase equipment(6) +266,567 +266,567 +— +— +— +$ +820,234 +$ +290,824 +$ +57,587 +$ +100,827 +$ +370,996 +(1) +No borrowings were outstanding on our revolving credit facility +as of December 31, 2010. Any borrowings that are drawn on +our revolving credit facility would be due at maturity +August 19, 2013. +(2) +Represents repayments of borrowing under the term loan portion +of the 2010 Credit Agreement. The term loan matures on +August 19, 2014. +(3) +Interest to be paid on term loan using 3.25% rate in effect as +of December 31, 2010. +(4) +Principal repayment of the Series A Senior Notes is +required at maturity on October 5, 2020. +(5) +Interest to be paid on the Series A Senior Notes using +4.97% coupon rate. +(6) +Represents commitments to purchase major equipment to be +delivered in 2011 based on expected delivery dates. +Off-Balance +Sheet Arrangements +We had no off-balance sheet arrangements at December 31, +2010. +Results +of Operations +Comparison +of the years ended December 31, 2010 and 2009 +The following tables summarize operations by business segment +for the years ended December 31, 2010 and 2009: +Year Ended December 31, +Contract Drilling +2010 +2009 +% Change +(Dollars in thousands) +Revenues +$ +1,081,898 +$ +599,287 +80.5 +% +Direct operating costs +$ +655,678 +$ +357,742 +83.3 +% +Selling, general and administrative +$ +5,279 +$ +4,340 +21.6 +% +Depreciation and impairment +$ +280,458 +$ +248,424 +12.9 +% +Operating income (loss) +$ +140,483 +$ +(11,219 +) +N/M +Operating days +61,244 +33,394 +83.4 +% +Average revenue per operating day +$ +17.67 +$ +17.95 +(1.6 +)% +Average direct operating costs per operating day +$ +10.71 +$ +10.71 +0.0 +% +Average rigs operating +168 +91 +84.6 +% +Capital expenditures +$ +655,550 +$ +395,376 +65.8 +% +25 +The demand for our contract drilling services is impacted by the +market price of natural gas and oil. The reactivation and +construction of new land drilling rigs in the United States in +recent years has also contributed to an excess capacity of land +drilling rigs compared to demand. The average market price of +natural gas and oil for each of the fiscal quarters and full +year in 2010 and 2009 follows: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2009: +Average natural gas price per Mcf(1) +$ +4.71 +$ +3.82 +$ +3.26 +$ +4.46 +$ +4.06 +Average oil price per Bbl(2) +$ +42.91 +$ +59.44 +$ +68.20 +$ +76.06 +$ +61.65 +2010: +Average natural gas price per Mcf(1) +$ +5.30 +$ +4.45 +$ +4.41 +$ +3.91 +$ +4.52 +Average oil price per Bbl(2) +$ +78.64 +$ +77.79 +$ +76.05 +$ +85.10 +$ +79.40 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +(2) +The average oil price represents the average monthly Cushing, OK +WTI spot price as reported by the United States Energy +Information Administration. +Revenues and direct operating costs increased in 2010 compared +to 2009 as a result of an increase in the number of operating +days. The increase in operating days was due to increased demand +largely caused by higher prices for natural gas and oil. Our +average number of rigs operating during 2009 included an average +of approximately six rigs operating under term contracts that +earned standby revenues of $22.3 million. Rigs on standby +earn a discounted dayrate as they do not have crews and have +lower costs. We had no significant standby revenue associated +with rigs operating under term contracts in 2010. We recognized +approximately $8.0 million of revenues during 2009 from the +early termination of term contracts. We had no such revenue from +the early termination of term contracts in 2010. Selling, +general and administrative expenses increased in 2010 primarily +as a result of increased personnel costs to support increased +activity levels. Significant capital expenditures were incurred +in 2010 and 2009 to build new drilling rigs, to modify and +upgrade our drilling rigs and to acquire additional related +equipment such as top drives, drill pipe, drill collars, +engines, fluid circulating systems, rig hoisting systems and +safety enhancement equipment. Depreciation expense increased as +a result of capital expenditures. Depreciation and impairment +expense includes approximately $4.2 million in 2010 and +approximately $10.5 million in 2009 of impairment charges +related to drilling equipment on drilling rigs that were removed +from our marketable fleet. We removed four rigs from our +marketable fleet in 2010 and removed 23 rigs from our marketable +fleet in 2009. +Year Ended December 31, +Pressure Pumping +2010 +2009 +% Change +(Dollars in thousands) +Revenues +$ +350,608 +$ +161,441 +117.2 +% +Direct operating costs +$ +235,100 +$ +124,100 +89.4 +% +Selling, general and administrative +$ +12,590 +$ +8,735 +44.1 +% +Depreciation and amortization +$ +40,724 +$ +27,589 +47.6 +% +Operating income +$ +62,194 +$ +1,017 +N/M +Fracturing jobs +1,527 +1,579 +(3.3 +)% +Other jobs +6,047 +5,399 +12.0 +% +Total jobs +7,574 +6,978 +8.5 +% +Average revenue per fracturing job +$ +180.21 +$ +70.88 +154.2 +% +Average revenue per other job +$ +12.47 +$ +9.17 +36.0 +% +Average revenue per total job +$ +46.29 +$ +23.14 +100.0 +% +Average direct operating costs per total job +$ +31.04 +$ +17.78 +74.6 +% +Capital expenditures +$ +51,064 +$ +43,144 +18.4 +% +26 +Revenues and direct operating costs increased primarily as a +result of the increase in the number of larger multi-stage +fracturing jobs, which was driven by higher demand for services +associated with unconventional reservoirs. Also contributing to +these increases was our acquisition of a pressure pumping +business on October 1, 2010 which significantly expanded +the size of our fleet of pressure pumping equipment and the +markets in which we provide pressure pumping services. This +acquisition was accounted for as a business combination and the +results of operations of the acquired business are included in +our pressure pumping segment results from the date of +acquisition. The acquired business contributed revenue of +$84.7 million and operating income of $22.8 million to +our operating results during the year ended December 31, +2010. +Our customers have increased their activities in the development +of unconventional reservoirs resulting in an increase in larger +multi-stage fracturing jobs associated therewith. As a result, +we have experienced an increase in the number of these larger +multi-stage fracturing jobs as a proportion of the total +fracturing jobs we performed. Average revenue per other job +increased as a result of increased pricing for the services +provided and a change in job mix. Selling, general and +administrative expenses in 2010 include $1.5 million +associated with the acquired business. The remaining increase in +selling, general and administrative expenses is due to +additional costs necessary to support increased business +activity in 2010. Significant capital expenditures have been +incurred in recent years to add capacity in our pressure pumping +segment. Depreciation and amortization expense in 2010 includes +$1.0 million in amortization of intangible assets and +$4.7 million in depreciation of property and equipment +associated with the acquired business. The remaining increase in +depreciation in 2010 compared to 2009 is a result of our recent +capital expenditures. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2010 +2009 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +30,425 +$ +21,218 +43.4 +% +Direct operating costs +$ +7,020 +$ +7,341 +(4.4 +)% +Depreciation, depletion and impairment +$ +10,950 +$ +12,927 +(15.3 +)% +Operating income +$ +12,455 +$ +950 +N/M +Capital expenditures +$ +23,067 +$ +7,341 +214.2 +% +Average net daily oil production (Bbls) +877 +761 +15.2 +% +Average net daily gas production (Mcf) +2,788 +3,225 +(13.6 +)% +Average oil sales price (per Bbl) +$ +77.26 +$ +58.09 +33.0 +% +Average gas sales price (per Mcf) +$ +5.60 +$ +4.32 +29.6 +% +Revenues increased due to higher average sales prices of oil and +natural gas and increased oil production partially offset by a +decline in natural gas production. Average net daily oil +production increased primarily due to the addition of new wells. +Average net daily natural gas production decreased primarily due +to production declines on existing wells. Depreciation, +depletion and impairment expense in 2010 includes approximately +$792,000 of oil and natural gas property impairments compared to +approximately $3.7 million of oil and natural gas property +impairments in 2009. Depletion expense increased approximately +$915,000 in 2010 compared to 2009. Capital expenditures +increased in 2010 as a result of greater drilling activity and +increased costs per well. +Year Ended December 31, +Corporate and Other +2010 +2009 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +35,173 +$ +30,860 +14.0 +% +Depreciation +$ +1,361 +$ +907 +50.1 +% +Provision for bad debts +$ +(2,000 +) +$ +3,810 +N/M +Net (gain) loss on asset disposals +$ +(22,812 +) +$ +3,385 +N/M +Acquisition-related expenses +$ +2,485 +$ +— +N/M +Interest income +$ +1,674 +$ +381 +339.4 +% +Interest expense +$ +12,772 +$ +4,148 +207.9 +% +Other income +$ +927 +$ +426 +117.6 +% +Capital expenditures +$ +8,409 +$ +6,785 +23.9 +% +27 +Selling, general and administrative expense increased in 2010 +primarily as a result of increased personnel costs. The +provision for bad debts in 2009 resulted from an increase in our +reserve on specific account balances based on the deteriorating +economic and credit environment at the time. The negative +provision for bad debts in 2010 is the result of reductions in +our reserve for specific accounts due to improved industry +conditions. Gains and losses on the disposal of assets are +treated as part of our corporate activities because such +transactions relate to corporate strategy decisions of our +executive management group. The gain on asset disposals in 2010 +includes a gain of $20.1 million related to the sale of +certain rights to explore and develop zones deeper than depths +that we generally target for certain of the oil and natural gas +properties in which we have working interests. Losses on asset +disposals in 2009 were primarily related to the disposal of +contract drilling equipment. Acquisition-related expenses in +2010 were incurred in connection with the acquisition of +pressure pumping and electric wireline businesses during the +fourth quarter of 2010. These expenses included certain legal +and other professional fees directly related to the transaction, +fees incurred in connection with the title transfers of the +acquired equipment and transition costs related to information +technology. Interest income increased due to the collection of +interest on a customer account as well as interest received on +prior overpayments of sales taxes in certain jurisdictions. +Interest expense in 2010 includes $3.3 million due to the +recognition of remaining deferred financing costs associated +with a revolving credit facility that was replaced in August +2010, and $1.3 million due to the recognition of financing +costs associated with a bridge facility that expired unused on +September 30, 2010. The remainder of the 2010 increase +relates to interest charges and the amortization of debt +issuance costs associated with the $100 million term loan +entered into in August 2010 and the $300 million Senior +Notes issued in October 2010. Capital expenditures increased in +2010 due to the ongoing implementation of a new enterprise +resource planning system. +Year Ended December 31, +Discontinued Operations: +2010 +2009 +% Change +(Dollars in thousands) +Electric wireline revenue +$ +5,712 +$ +— +N/M +Electric wireline direct operating costs +$ +4,962 +$ +— +N/M +Drilling and completion fluids revenue +$ +3,737 +$ +79,786 +(95.3 +)% +Drilling and completion fluids direct operating costs +$ +3,307 +$ +74,180 +(95.5 +)% +Selling, general and administrative +$ +358 +$ +7,192 +(95.0 +)% +Depreciation +$ +166 +$ +2,287 +(92.7 +)% +Impairment of assets held for sale +$ +2,155 +$ +1,900 +13.4 +% +Net gain on asset disposals/retirements +$ +— +$ +(125 +) +(100.0 +% +Other operating expense +$ +— +$ +890 +(100.0 +)% +Income tax expense (benefit) +$ +(543 +) +$ +(2,208 +) +(75.4 +)% +Loss from discontinued operations, net of income taxes +$ +(956 +) +$ +(4,330 +) +(77.9 +)% +On January 27, 2011, we sold our electric wireline +business, which had been acquired by us on October 1, 2010. +The results of operations of this business have been classified +as a discontinued operation and the assets held for sale at +December 31, 2010 are presented at net realizable value in +the consolidated balance sheet. On January 20, 2010, we +sold our drilling and completion fluids services business which +had previously been presented as one of our reportable operating +segments. Due to our exit from this business, we have classified +our drilling and completion fluids operating segment as a +discontinued operation. Impairment of assets held for sale in +2010 and 2009 reflects the transaction-related costs recorded to +reduce the carrying value of the assets sold to their net +realizable value at December 31, 2010, and 2009. +28 +Comparison +of the years ended December 31, 2009 and 2008 +The following tables summarize operations by business segment +for the years ended December 31, 2009 and 2008: +Year Ended December 31, +Contract Drilling +2009 +2008 +% Change +(Dollars in thousands) +Revenues +$ +599,287 +$ +1,804,026 +(66.8 +)% +Direct operating costs +$ +357,742 +$ +1,038,327 +(65.5 +)% +Selling, general and administrative +$ +4,340 +$ +5,363 +(19.1 +)% +Depreciation and impairment +$ +248,424 +$ +239,700 +3.6 +% +Operating income (loss) +$ +(11,219 +) +$ +520,636 +N/M +Operating days +33,394 +93,068 +(64.1 +)% +Average revenue per operating day +$ +17.95 +$ +19.38 +(7.4 +)% +Average direct operating costs per operating day +$ +10.71 +$ +11.16 +(4.0 +)% +Average rigs operating +91 +254 +(64.2 +)% +Capital expenditures +$ +395,376 +$ +360,645 +9.6 +% +The demand for our contract drilling services is impacted by the +market price of natural gas and oil. The reactivation and +construction of new land drilling rigs in the United States in +recent years has also contributed to an excess capacity of land +drilling rigs compared to demand. The average market price of +natural gas and oil for each of the fiscal quarters and full +year in 2009 and 2008 follow: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2008: +Average natural gas price per Mcf(1) +$ +8.92 +$ +11.74 +$ +9.28 +$ +6.60 +$ +9.13 +Average oil price per Bbl(2) +$ +97.94 +$ +123.95 +$ +118.05 +$ +58.35 +$ +99.57 +2009: +Average natural gas price per Mcf(1) +$ +4.71 +$ +3.82 +$ +3.26 +$ +4.46 +$ +4.06 +Average oil price per Bbl(2) +$ +42.91 +$ +59.44 +$ +68.20 +$ +76.06 +$ +61.65 +(1) +The average natural gas price represents the Henry Hub Spot +price as reported by the United States Energy Information +Administration. +(2) +The average oil price represents the average monthly Cushing, OK +WTI spot price as reported by the United States Energy +Information Administration. +Revenues and direct operating costs decreased in 2009 compared +to 2008 primarily as a result of a decrease in the number of +operating days. The decrease in operating days was due to +decreased demand largely caused by lower commodity prices for +natural gas and oil. Our average number of rigs operating during +2009 included an average of approximately six rigs operating +under term contracts that earned standby revenues of +$22.3 million. This represented an increase from an average +of approximately one rig operating under a term contract that +earned standby revenues of $4.7 million in 2008. Rigs on +standby earn a discounted dayrate as they do not have crews and +have lower costs. We recognized approximately $8.0 million +of revenues during 2009 from the early termination of drilling +contracts compared to approximately $1.3 million in 2008. +Average revenue per operating day decreased in 2009 primarily +due to decreases in dayrates for rigs that were operating in the +spot market and the expiration of term contracts that were +entered into at higher rates. Average direct operating costs per +operating day decreased in 2009 primarily due to decreases in +labor and repair costs. Significant capital expenditures were +incurred in 2009 and 2008 to build new drilling rigs, to modify +and upgrade our drilling rigs and to acquire additional related +equipment such as drill pipe, drill collars, engines, fluid +circulating systems, rig hoisting systems and safety enhancement +equipment. Depreciation expense increased as a result of those +capital expenditures. Depreciation and impairment +29 +expense includes approximately $10.5 million in 2009 and +approximately $10.4 million in 2008 of impairment charges +related to drilling equipment on drilling rigs that were removed +from our marketable fleet. We removed 23 rigs from our +marketable fleet in 2009 and removed 22 rigs from our marketable +fleet in 2008. +Year Ended December 31, +Pressure Pumping +2009 +2008 +% Change +(Dollars in thousands) +Revenues +$ +161,441 +$ +217,494 +(25.8 +)% +Direct operating costs +$ +124,100 +$ +147,377 +(15.8 +)% +Selling, general and administrative +$ +8,735 +$ +8,498 +2.8 +% +Depreciation +$ +27,589 +$ +19,600 +40.8 +% +Operating income +$ +1,017 +$ +42,019 +(97.6 +)% +Fracturing jobs +1,579 +2,898 +(45.5 +)% +Other jobs +5,399 +9,162 +(41.1 +)% +Total jobs +6,978 +12,060 +(42.1 +)% +Average revenue per fracturing job +$ +70.88 +$ +49.62 +42.8 +% +Average revenue per other job +$ +9.17 +$ +8.04 +14.1 +% +Average revenue per total job +$ +23.14 +$ +18.03 +28.3 +% +Average direct operating costs per total job +$ +17.78 +$ +12.22 +45.5 +% +Capital expenditures +$ +43,144 +$ +61,289 +(29.6 +)% +Our customers have increased their activities in the development +of unconventional reservoirs resulting in an increase in larger +multi-stage fracturing jobs associated therewith. As a result, +we have experienced an increase in the number of these larger +multi-stage fracturing jobs as a proportion of the total +fracturing jobs we performed. In 2009 we experienced a decrease +in smaller traditional pressure pumping jobs due to depressed +commodity prices, which contributed to the overall decrease in +revenue and direct operating costs. In anticipation of increased +activity associated with the unconventional reservoirs in the +Appalachian Basin, we added facilities, equipment and personnel. +Delays in the development of these reservoirs and lower +commodity prices caused a slower increase in customer activity +than we had expected, negatively impacting the profitability of +this business. Significant capital expenditures have been +incurred in recent years to add capacity. Depreciation expense +increased as a result of our recent capital expenditures. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2009 +2008 +% Change +(Dollars in thousands, except commodity prices) +Revenues +$ +21,218 +$ +42,360 +(49.9 +)% +Direct operating costs +$ +7,341 +$ +12,793 +(42.6 +)% +Depreciation, depletion and impairment +$ +12,927 +$ +15,856 +(18.5 +)% +Operating income +$ +950 +$ +13,711 +(93.1 +)% +Capital expenditures +$ +7,341 +$ +22,981 +(68.1 +)% +Average net daily oil production (Bbls) +761 +801 +(5.0 +)% +Average net daily gas production (Mcf) +3,225 +3,755 +(14.1 +)% +Average oil sales price (per Bbl) +$ +58.09 +$ +98.70 +(41.1 +)% +Average gas sales price (per Mcf) +$ +4.32 +$ +9.77 +(55.8 +)% +Revenues decreased due to lower average sales prices and lower +average net daily production of oil and natural gas. Average net +daily oil and natural gas production decreased primarily due to +production declines on existing wells. Direct operating costs +decreased primarily due to decreases in seismic expenses as well +as decreased production taxes and other production costs. +Depreciation, depletion and impairment expense in 2009 includes +approximately $3.7 million of oil and natural gas property +impairments compared to approximately $4.4 million of oil +and natural gas property impairments in 2008. Depletion expense +decreased approximately $2.3 million +30 +primarily due to lower production and the impact of decreases in +the carrying value of properties resulting from previous +impairment charges. Capital expenditures decreased in 2009 as a +result of declines in commodity prices. +Year Ended December 31, +Corporate and Other +2009 +2008 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +30,860 +$ +29,412 +4.9 +% +Depreciation +$ +907 +$ +834 +8.8 +% +Provision for bad debts +$ +3,810 +$ +4,350 +(12.4 +)% +Net (gain) loss on asset disposals +$ +3,385 +$ +(4,163 +) +N/M +Interest income +$ +381 +$ +1,553 +(75.5 +)% +Interest expense +$ +4,148 +$ +630 +558.4 +% +Other income +$ +426 +$ +502 +(15.1 +)% +Capital expenditures +$ +6,785 +$ +511 +N/M +Selling, general and administrative expense increased in 2009 +primarily as a result of increased professional fees. The +provision for bad debts resulted from an increase in our reserve +on specific account balances based on the deteriorating economic +and credit environment in 2008 and 2009. Gains and losses on the +disposal of assets are treated as part of our corporate +activities because such transactions relate to corporate +strategy decisions of our executive management group. Losses on +asset disposals in 2009 were primarily related to the disposal +of contract drilling equipment. Gains on asset disposals in 2008 +were primarily related to gains on the sale of contract drilling +equipment and the sale of oil and natural gas properties. +Interest expense increased in 2009 due to the amortization of +debt issuance costs and increased fees associated with +outstanding letters of credit and the unused portion of the +revolving credit facility that was put into place in 2009. +Capital expenditures increased in 2009 due to the purchase and +ongoing implementation of a new enterprise resource planning +system. +Year Ended December 31, +Discontinued Operations: +2009 +2008 +% Change +(Dollars in thousands) +Drilling and completion fluids revenue +$ +79,786 +$ +145,246 +(45.1 +)% +Drilling and completion fluids direct operating costs +$ +74,180 +$ +126,900 +(41.5 +)% +Selling, general and administrative +$ +7,192 +$ +10,110 +(28.9 +)% +Depreciation +$ +2,287 +$ +2,830 +(19.2 +)% +Goodwill impairment +$ +— +$ +9,964 +(100.0 +)% +Impairment of assets held for sale +$ +1,900 +$ +— +N/M +Net gain on asset disposals/retirements +$ +(125 +) +$ +(155 +) +(19.4 +)% +Other operating expense +$ +890 +$ +— +N/M +Net interest expense +$ +— +$ +7 +(100.0 +)% +Income tax expense (benefit) +$ +(2,208 +) +$ +2,389 +N/M +Loss from discontinued operations, net of income taxes +$ +(4,330 +) +$ +(6,799 +) +36.3 +% +On January 20, 2010, we exited our drilling and completion +fluids services business, which had previously been presented as +one of our reportable operating segments. Due to our exit from +this business, we have classified our drilling and completion +fluids operating segment as a discontinued operation. +Accordingly, the assets and liabilities of this business, along +with its results of operations, were reclassified for all +periods presented. Drilling and completion fluids revenue and +direct operating costs decreased in 2009 due to decreased sales +volume both on land and offshore in the Gulf of Mexico. Drilling +and completion fluids selling, general and administrative +expenses decreased in 2009 primarily due to a decrease in +compensation costs for sales and support personnel due to +headcount reductions. Goodwill impairment was recognized in the +drilling and completion fluids reporting unit in 2008 as a +result of our annual impairment testing which indicated that the +fair value of goodwill in that reporting unit was zero. +Impairment of assets held for sale in 2009 of $1.9 million +represents the transaction-related costs recorded to reduce the +carrying value of the assets sold to their net realizable value +at December 31, 2009. In 2008, +31 +income tax expense was recognized despite a pre-tax loss in the +drilling and completion fluids business due to the fact that the +goodwill impairment recorded in that year was not deductible for +tax purposes. +Income +Taxes +Year Ended December 31, +2010 +2009 +2008 +(Dollars in thousands) +Income (loss) from continuing operations before income tax +$ +190,754 +$ +(51,555 +) +$ +547,358 +Income tax expense (benefit) +72,856 +(17,595 +) +193,490 +Effective tax rate +38.2 +% +34.1 +% +35.3 +% +The effective tax rate is a result of a Federal rate of 35.0% +adjusted as follows: +2010 +2009 +2008 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.1 +4.7 +1.7 +Permanent differences +2.3 +(5.7 +) +(1.2 +) +Other, net +(0.2 +) +0.1 +(0.2 +) +Effective tax rate +38.2 +% +34.1 +% +35.3 +% +For 2008, the permanent difference indicated above was largely +attributable to our Domestic Production Activities Deduction. +The Domestic Production Activities Deduction was enacted as part +of the American Jobs Creation Act of 2004 (as revised by the +Emergency Economic Stabilization Act of 2008) and allows a +deduction of 6% in both 2008 and 2009 and 9% in 2010 and +thereafter on the lesser of qualified production activities +income or taxable income. The permanent differences for 2010 and +2009 reflect the recapture of a portion of this deduction due to +the planned carryback of the 2010 net operating loss to +prior years and the carryback of the 2009 net operating loss to +prior years. This recapture resulted in a negative effective +rate impact in 2009 due to the Company having a loss before +income taxes in that year. +We record deferred Federal income taxes based primarily on the +temporary differences between the book and tax bases of our +assets. Deferred tax assets and liabilities are measured using +enacted tax rates expected to apply to taxable income in the +year in which those temporary differences are expected to be +settled. As a result of fully recognizing the benefit of our +deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We recognized deferred tax expense +of approximately $147 million in 2010, $101 million in +2009 and $65.4 million in 2008. +On January 1, 2010, we converted our Canadian operations +from a Canadian branch to a controlled foreign corporation for +Federal income tax purposes. Because the statutory tax rates in +Canada are lower than those in the United States, this +transaction triggered a $5.1 million reduction in deferred +tax liabilities, which is being amortized as a reduction to +deferred income tax expense over the weighted average remaining +useful life of the Canadian assets. +As a result of the above conversion, our Canadian assets are no +longer subject to United States taxation, provided that the +related unremitted earnings are permanently reinvested in +Canada. Effective January 1, 2010, we have elected to +permanently reinvest these unremitted earnings in Canada, and +intend to do so for the foreseeable future. As a result, no +deferred United States Federal or state income taxes have been +provided on such unremitted foreign earnings, which totaled +approximately $6.3 million as of December 31, 2010. +Volatility +of Oil and Natural Gas Prices and its Impact on Operations and +Financial Condition +Our revenue, profitability, financial condition and rate of +growth are substantially dependent upon prevailing prices for +natural gas and oil. For many years, oil and natural gas prices +and markets have been extremely volatile. Prices are affected by +market supply and demand factors as well as international +military, political and economic conditions, and the ability of +OPEC to set and maintain production and price targets. All of +these factors are beyond our control. During 2008, the monthly +average market price of natural gas (monthly average Henry Hub +price as reported by the United States Energy Information +Administration) peaked in June at $13.06 per Mcf before rapidly +32 +declining to an average of $5.99 per Mcf in December. In 2009, +the monthly average market price of natural gas declined further +to a low of $3.06 per Mcf in September. This decline in the +market price of natural gas resulted in our customers +significantly reducing their drilling activities beginning in +the fourth quarter of 2008, and drilling activities remained low +throughout 2009 before recovering somewhat in 2010. Construction +of new land drilling rigs in the United States during the last +ten years has significantly contributed to excess capacity. As a +result of these factors, our average number of rigs operating +has declined significantly from historic highs. We expect oil +and natural gas prices to continue to be volatile and to affect +our financial condition, operations and ability to access +sources of capital. Low market prices for natural gas and oil +would likely result in lower demand for our drilling rigs and +pressure pumping services and adversely affect our operating +results, financial condition and cash flows. +The North American land drilling industry has experienced +downturns in demand during the last decade. During these +periods, there have been substantially more drilling rigs +available than necessary to meet demand. As a result, drilling +contractors have had difficulty sustaining profit margins and, +at times, have incurred losses during the downturn periods. +Impact of +Inflation +Inflation has not had a significant impact on our operations +during the three years in the period ended December 31, +2010. We believe that inflation will not have a significant +near-term impact on our financial position. +Recently +Issued Accounting Standards +In June 2009, the FASB issued a new accounting standard that +amends the accounting and disclosure requirements for the +consolidation of variable interest entities. This new standard +removes the previously existing exception from applying +consolidation guidance to qualifying special-purpose entities +and requires ongoing reassessments of whether an enterprise is +the primary beneficiary of a variable interest entity. Prior to +this new standard, generally accepted accounting principles +required reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for us on January 1, 2010. The +adoption of this standard did not impact our consolidated +financial statements. +In October 2009, the FASB issued a new accounting standard that +addresses the accounting for multiple-deliverable revenue +arrangements to enable vendors to account for deliverables +separately rather than as a combined unit. This new standard +addresses how to separate deliverables and how to measure and +allocate arrangement consideration to one or more units of +accounting. Existing accounting standards require a vendor to +use objective and reliable evidence of fair value for the +undelivered items or the residual method to separate +deliverables in a multiple-deliverable arrangement. Under the +new standard, it is expected that multiple-deliverable +arrangements will be separated in more circumstances than under +current requirements. The new standard establishes a hierarchy +for determining the selling price of a deliverable for purposes +of allocating revenue to multiple deliverables. The selling +price used will be based on vendor-specific objective evidence +if available, third-party evidence if vendor-specific objective +evidence is not available, or estimated selling price if neither +vendor-specific objective evidence nor third-party evidence is +available. The new standard must be prospectively applied to all +revenue arrangements entered into in fiscal years beginning on +or after June 15, 2010 and became effective for us on +January 1, 2011. The adoption of this standard did not have +a material impact on our consolidated financial position, +results of operations or cash flows. +In December 2010, the FASB issued an accounting standard update +that addresses the disclosure of supplementary pro forma +information for business combinations. This update clarifies +that when public entities are required to disclose pro forma +information for business combinations that occurred in the +current reporting period, the pro forma information should be +presented as if the business combination occurred as of the +beginning of the previous fiscal year when comparative financial +statements are presented. This update is effective prospectively +for business combinations for which the acquisition date is on +or after the beginning of the first annual reporting period +33 +beginning on or after December 15, 2010. Early adoption is +permitted. We elected to early adopt this update and this early +adoption did not have an impact on our consolidated financial +position, results of operations or cash flows. +Item 7A. +Quantitative +and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk +associated with any borrowings that we have under our term +credit facility or our revolving credit facility. Interest is +paid on the outstanding principal amount of borrowings at a +floating rate based on, at our election, LIBOR or a base rate. +The margin on LIBOR loans ranges from 2.75% to 3.75% and the +margin on base rate loans ranges from 1.75% to 2.75%, based on +our debt to capitalization ratio. At December 31, 2010, the +margin on LIBOR loans was 2.75% and the margin on base rate +loans was 1.75%. As of December 31, 2010, we had no +borrowings outstanding under our revolving credit facility and +$98.8 million outstanding under our term credit facility at +an interest rate of 3.125%. The interest rate on the borrowing +outstanding under our term credit facility is variable and +adjusts at each interest payment date based on our election of +LIBOR or the base rate. A one percent increase in the interest +rate on the borrowing outstanding under our term credit facility +as of December 31, 2010 would increase our annual cash +interest expense by $987,500. +We conduct a portion of our business in Canadian dollars through +our Canadian land-based drilling operations. The exchange rate +between Canadian dollars and U.S. dollars has fluctuated +during the last several years. If the value of the Canadian +dollar against the U.S. dollar weakens, revenues and +earnings of our Canadian operations will be reduced and the +value of our Canadian net assets will decline when they are +translated to U.S. dollars. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +Item 8. +Financial +Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the +end of Part IV hereof beginning at +page F-1, +Index to Consolidated Financial Statements, and are incorporated +herein by this reference. +Item 9. +Changes +in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. +Controls +and Procedures. +Disclosure +Controls and Procedures: +Under the supervision and with the participation of our +management, including our Chief Executive Officer (CEO) and +Chief Financial Officer (CFO), we conducted an evaluation of the +effectiveness of our disclosure controls and procedures, as such +term is defined in +Rules 13a-15(e) +and +15d-15(e) +promulgated under the Exchange Act, as of the end of the period +covered by this Report. Based on this evaluation, our CEO and +CFO concluded that, as of December 31, 2010, our disclosure +controls and procedures were effective to ensure that +information required to be disclosed by us in reports that we +file or submit under the Exchange Act is recorded, processed, +summarized and reported within the time periods specified in SEC +rules and forms and is accumulated and reported to our +management, including our CEO and CFO, as appropriate to allow +timely decisions regarding required disclosure. +Management’s +Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining +adequate internal control over financial reporting, as defined +in Exchange Act +Rule 13a-15(f). +Under the supervision and with the participation of our +management, including our CEO and CFO, we carried out an +evaluation of the effectiveness of our internal control over +financial reporting as of December 31, 2010, based on the +Internal Control-Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway +Commission. Based on this evaluation, our management has +concluded that our internal control over financial reporting was +effective as of December 31, 2010. +34 +Our wholly-owned subsidiaries, Universal Pressure Pumping, Inc. +(“UPP”) and Universal Wireline, Inc. +(“UWL”), were excluded from our evaluation of the +effectiveness of our internal control over financial reporting +as of December 31, 2010. UPP and UWL were formed in 2010 +for the purpose of acquiring the assets of pressure pumping and +wireline businesses in a business acquisition which closed on +October 1, 2010. These subsidiaries were excluded from the +scope of our review due to the fact that the acquisition closed +in the fourth quarter of 2010, at which time we began +integrating the acquired businesses into our existing internal +controls over financial reporting. The acquired businesses +represented approximately 6 percent of consolidated +revenues for the year ended December 31, 2010 and +approximately 9 percent of consolidated total assets as of +December 31, 2010. +The effectiveness of our internal control over financial +reporting as of December 31, 2010 has been audited by +PricewaterhouseCoopers LLP, an independent registered public +accounting firm, as stated in their report which appears on +page F-2 +of this Report and which is incorporated by reference into +Item 8 of this Report. +Changes +in Internal Control over Financial Reporting: +There have been no changes in our internal control over +financial reporting during the most recently completed fiscal +quarter that have materially affected, or are reasonably likely +to materially affect, our internal control over financial +reporting. As discussed above, we began integrating the acquired +pressure pumping and wireline businesses into our existing +internal control over financial reporting during the most +recently completed fiscal quarter. +Item 9B. +Other +Information +None. +35 +PART III +The information required by Part III is omitted from this +Report because we expect to file a definitive proxy statement +(the “Proxy Statement”) pursuant to +Regulation 14A of the Securities Exchange Act of 1934 no +later than 120 days after the end of the fiscal year +covered by this Report and certain information included therein +is incorporated herein by reference. +Item 10. +Directors, +Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +We have adopted a Code of Business Conduct and Ethics for Senior +Financial Executives, which covers, among others, our principal +executive officer, principal financial officer and principal +accounting officer. The text of this code is located on our +website under “Governance.” Our Internet address is +www.patenergy.com . We intend to disclose any amendments +to or waivers from this code on our website. +Item 11. +Executive +Compensation. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 12. +Security +Ownership of Certain Beneficial Owners and Management and +Related Stockholder Matters. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +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. +36 +PART IV +Item 15. +Exhibits +and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial Statements on +page F-1 +of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts +is filed herewith on +page S-1. +All other financial statement schedules have been omitted +because they are not applicable or the information required +therein is included elsewhere in the financial statements or +notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by +reference herein. +2 +.1 +Asset Purchase Agreement dated July 2, 2010 by and among +Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a +Universal Pressure Pumping, Inc.), Key Energy Pressure Pumping +Services, LLC, Key Electric Wireline Services, LLC and Key +Energy Services, Inc. (filed July 6, 2010 as +Exhibit 2.1 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +2 +.2 +Letter Agreement dated September 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.2 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +2 +.3 +Letter Agreement dated October 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned to REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +37 +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.6 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.8 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.9 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.10 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.11 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.12 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.13 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.1 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.14 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed April 27, 2010 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.15 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.3 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.16 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time (filed February 19, 2010 as +Exhibit 10.9 to the Company’s Annual Report on +Form 10-K for the year ended December 31, 2009 and +incorporated herein by reference).* +10 +.17 +Form of Amendment to Cash-Settled Performance Unit Award +Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended March 31, 2010 and +incorporated herein by reference).* +10 +.18 +Form of Share-Settled Performance Unit Award Agreement under the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed +August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2010 and +incorporated herein by reference).* +38 +10 +.19 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +10 +.27 +Credit Agreement dated August 19, 2010, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer and lender and +each of the other letter of credit issuer and lender parties +thereto (filed August 19, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.28 +Note Purchase Agreement dated October 5, 2010 by and among +Patterson-UTI Energy, Inc. and the purchasers named therein +(filed October 6, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2010, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Income, (iii) the Consolidated Statements of +Changes in Stockholders’ Equity, (iv) the Consolidated +Statements of Cash Flows, and (v) Notes to Consolidated +Financial Statements, tagged as blocks of text. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. +39 +INDEX TO +CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of Independent Registered Public +Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of +December 31, 2010 and 2009 +F-3 +Consolidated Statements of Operations for the +years ended December 31, 2010, 2009 and 2008 +F-4 +Consolidated Statements of Changes In +Stockholders’ Equity for the years ended December 31, +2010, 2009 and 2008 +F-5 +Consolidated Statements of Cash Flows for the +years ended December 31, 2010, 2009 and 2008 +F-6 +Notes to Consolidated Financial Statements +F-7 +Financial Statement Schedule +S-1 +F-1 +Report of +Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders +of Patterson-UTI Energy, Inc.: +In our opinion, the consolidated financial statements listed in +the accompanying index present fairly, in all material respects, +the financial position of Patterson-UTI Energy, Inc. and its +subsidiaries (the “Company”) at December 31, 2010 +and 2009, and the results of their operations and their cash +flows for each of the three years in the period ended +December 31, 2010 in conformity with accounting principles +generally accepted in the United States of America. In addition, +in our opinion, the financial 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 financial +statements. Also in our opinion, the Company maintained, in all +material respects, effective internal control over financial +reporting as of December 31, 2010, based on criteria +established in Internal Control — Integrated +Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). The +Company’s management is responsible for these financial +statements and financial statement schedule, for maintaining +effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over +financial reporting, included in Management’s Report on +Internal Control over Financial Reporting appearing under +Item 9A. Our responsibility is to express opinions on these +financial statements, on the financial statement schedule, and +on the Company’s internal control over financial reporting +based on our integrated audits. We conducted our audits in +accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we +plan and perform the audits to obtain reasonable assurance about +whether the financial statements are free of material +misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test +basis, evidence supporting the amounts and disclosures in the +financial statements, assessing the accounting principles used +and significant estimates made by management, and evaluating the +overall financial statement presentation. Our audit of internal +control over financial reporting included obtaining an +understanding of internal control over financial reporting, +assessing the risk that a material weakness exists, and testing +and evaluating the design and operating effectiveness of +internal control based on the assessed risk. Our audits also +included performing such other procedures as we considered +necessary in the circumstances. We believe that our audits +provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +As described in Management’s Report on Internal Control +Over Financial Reporting, management has excluded Universal +Pressure Pumping, Inc. and Universal Wireline, Inc. from its +assessment of internal control over financial reporting as of +December 31, 2010 because they were formed in 2010 to +acquire certain pressure pumping and wireline businesses in a +business combination during the fourth quarter of 2010. We have +also excluded Universal Pressure Pumping, Inc. and Universal +Wireline, Inc. from our audit of internal control over financial +reporting. As of December 31, 2010, Universal Pressure +Pumping, Inc. and Universal Wireline, Inc. were wholly-owned +subsidiaries whose total assets and total revenues represented +9 percent and 6 percent, respectively, of the related +consolidated financial statement amounts as of and for the year +ended December 31, 2010. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 14, 2011 +F-2 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2010 +2009 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +27,612 +$ +49,877 +Accounts receivable, net of allowance for doubtful accounts of +$5,114 and $10,911 at December 31, 2010 and 2009, +respectively +337,167 +164,498 +Federal and state income taxes receivable +75,062 +118,869 +Inventory +17,215 +6,941 +Deferred tax assets, net +26,815 +32,877 +Assets held for sale +23,370 +42,424 +Other +50,169 +40,475 +Total current assets +557,410 +455,961 +Property and equipment, net +2,620,900 +2,110,402 +Goodwill and intangible assets +179,683 +86,234 +Deposits on equipment purchases +51,084 +914 +Other +13,954 +8,641 +Total assets +$ +3,423,031 +$ +2,662,152 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +162,400 +$ +83,700 +Accrued expenses +147,315 +108,750 +Current portion of long term debt +6,250 +— +Total current liabilities +315,965 +192,450 +Long term debt +392,500 +— +Deferred tax liabilities, net +511,422 +381,656 +Other +15,537 +6,346 +Total liabilities +1,235,424 +580,452 +Commitments and contingencies (see Note 9) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 181,537,568 and 180,828,773 issued and 154,193,754 and +153,610,785 outstanding at December 31, 2010 and 2009, +respectively +1,815 +1,808 +Additional paid-in capital +796,641 +781,635 +Retained earnings +1,987,999 +1,901,853 +Accumulated other comprehensive income +21,597 +14,996 +Treasury stock, at cost, 27,343,814 shares and +27,217,988 shares at December 31, 2010 and 2009, +respectively +(620,445 +) +(618,592 +) +Total stockholders’ equity +2,187,607 +2,081,700 +Total liabilities and stockholders’ equity +$ +3,423,031 +$ +2,662,152 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +Year Ended December 31, +2010 +2009 +2008 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,081,898 +$ +599,287 +$ +1,804,026 +Pressure pumping +350,608 +161,441 +217,494 +Oil and natural gas +30,425 +21,218 +42,360 +Total operating revenues +1,462,931 +781,946 +2,063,880 +Operating costs and expenses: +Contract drilling +655,678 +357,742 +1,038,327 +Pressure pumping +235,100 +124,100 +147,377 +Oil and natural gas +7,020 +7,341 +12,793 +Depreciation, depletion, amortization and impairment +333,493 +289,847 +275,990 +Selling, general and administrative +53,042 +43,935 +43,273 +Net (gain) loss on asset disposals +(22,812 +) +3,385 +(4,163 +) +Provision for bad debts +(2,000 +) +3,810 +4,350 +Acquisition-related expenses +2,485 +— +— +Total operating costs and expenses +1,262,006 +830,160 +1,517,947 +Operating income (loss) +200,925 +(48,214 +) +545,933 +Other income (expense): +Interest income +1,674 +381 +1,553 +Interest expense +(12,772 +) +(4,148 +) +(630 +) +Other +927 +426 +502 +Total other income (expense) +(10,171 +) +(3,341 +) +1,425 +Income (loss) from continuing operations before income taxes +190,754 +(51,555 +) +547,358 +Income tax expense (benefit): +Current +(74,634 +) +(119,038 +) +128,098 +Deferred +147,490 +101,443 +65,392 +Total income tax expense (benefit) +72,856 +(17,595 +) +193,490 +Income (loss) from continuing operations +117,898 +(33,960 +) +353,868 +Loss from discontinued operations, net of income taxes +(956 +) +(4,330 +) +(6,799 +) +Net income (loss) +$ +116,942 +$ +(38,290 +) +$ +347,069 +Basic income (loss) per common share: +Income (loss) from continuing operations +$ +0.77 +$ +(0.22 +) +$ +2.29 +Loss from discontinued operations, net of income taxes +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Net income (loss) +$ +0.76 +$ +(0.25 +) +$ +2.25 +Diluted income (loss) per common share: +Income (loss) from continuing operations +$ +0.76 +$ +(0.22 +) +$ +2.27 +Loss from discontinued operations, net of income taxes +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Net income (loss) +$ +0.76 +$ +(0.25 +) +$ +2.23 +Weighted average number of common shares outstanding: +Basic +152,772 +152,069 +153,379 +Diluted +153,276 +152,069 +154,358 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.60 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2007 +177,386 +$ +1,773 +$ +703,581 +$ +1,716,620 +$ +20,207 +$ +(546,151 +) +$ +1,896,030 +Comprehensive income: +Net income +— +— +— +347,069 +— +— +347,069 +Foreign currency translation adjustment, (net of tax of $8,368) +— +— +— +— +(14,433 +) +— +(14,433 +) +Total comprehensive income +— +— +— +347,069 +(14,433 +) +— +332,636 +Issuance of restricted stock +577 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(75 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +2,304 +23 +25,525 +— +— +— +25,548 +Stock-based compensation +— +— +20,131 +— +— +— +20,131 +Tax benefit related to stock-based compensation +— +— +16,280 +— +— +— +16,280 +Payment of cash dividends +— +— +— +(92,865 +) +— +— +(92,865 +) +Purchase of treasury stock +— +— +— +— +— +(70,818 +) +(70,818 +) +Balance, December 31, 2008 +180,192 +1,801 +765,512 +1,970,824 +5,774 +(616,969 +) +2,126,942 +Comprehensive income (loss): +Net loss +— +— +— +(38,290 +) +— +— +(38,290 +) +Foreign currency translation adjustment, (net of tax of $5,347) +— +— +— +— +9,222 +— +9,222 +Total comprehensive loss +— +— +— +(38,290 +) +9,222 +— +(29,068 +) +Issuance of restricted stock +604 +6 +(6 +) +— +— +— +— +Vesting of restricted stock units +6 +— +— +— +— +— +— +Forfeitures of restricted stock +(56 +) +— +— +— +— +— +— +Exercise of stock options +83 +1 +568 +— +— +— +569 +Stock-based compensation +— +— +18,565 +— +— +— +18,565 +Tax expense related to stock-based compensation +— +— +(3,004 +) +— +— +— +(3,004 +) +Payment of cash dividends +— +— +— +(30,681 +) +— +— +(30,681 +) +Purchase of treasury stock +— +— +— +— +— +(1,623 +) +(1,623 +) +Balance, December 31, 2009 +180,829 +1,808 +781,635 +1,901,853 +14,996 +(618,592 +) +2,081,700 +Comprehensive income: +Net income +— +— +— +116,942 +— +— +116,942 +Foreign currency translation adjustment, (net of tax of $2,814) +— +— +— +— +6,601 +— +6,601 +Total comprehensive income +— +— +— +116,942 +6,601 +— +123,543 +Issuance of restricted stock +700 +7 +(7 +) +— +— +— +— +Vesting of restricted stock units +7 +— +— +— +— +— +— +Forfeitures of restricted stock +(59 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +61 +1 +524 +— +— +— +525 +Stock-based compensation +— +— +16,779 +— +— +— +16,779 +Tax expense related to stock-based compensation +— +— +(2,291 +) +— +— +— +(2,291 +) +Payment of cash dividends +— +— +— +(30,796 +) +— +— +(30,796 +) +Purchase of treasury stock +— +— +— +— +— +(1,853 +) +(1,853 +) +Balance, December 31, 2010 +181,538 +$ +1,815 +$ +796,641 +$ +1,987,999 +$ +21,597 +$ +(620,445 +) +$ +2,187,607 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Year Ended December 31, +2010 +2009 +2008 +(In thousands) +Cash flows from operating activities: +Net income (loss) +$ +116,942 +$ +(38,290 +) +$ +347,069 +Adjustments to reconcile net income (loss) to net cash provided +by operating activities: +Depreciation, depletion, amortization and impairment +333,493 +289,847 +275,990 +Provision for bad debts +(2,000 +) +3,810 +4,350 +Dry holes and abandonments +519 +129 +1,617 +Deferred income tax expense +147,490 +101,443 +65,392 +Stock-based compensation expense +16,779 +18,214 +19,688 +Net (gain) loss on asset disposals +(22,812 +) +3,385 +(4,163 +) +Tax expense related to stock-based compensation +(2,291 +) +(3,004 +) +— +Changes in operating assets and liabilities: +Accounts receivable +(178,444 +) +213,813 +(30,777 +) +Income taxes receivable/payable +43,522 +(108,664 +) +(11,258 +) +Inventory and other assets +(8,772 +) +14,178 +2,498 +Accounts payable +49,576 +(52,673 +) +6,486 +Accrued expenses +18,072 +(21,178 +) +(4,474 +) +Other liabilities +3,234 +(92 +) +1,242 +Net cash provided by operating activities of discontinued +operations +10,390 +32,759 +1,344 +Net cash provided by operating activities +525,698 +453,677 +675,004 +Cash flows from investing activities: +Acquisitions +(238,022 +) +— +— +Purchases of property and equipment +(738,090 +) +(452,646 +) +(445,426 +) +Proceeds from disposal of assets +29,409 +3,359 +11,436 +Net cash provided by (used in) investing activities of +discontinued operations +42,638 +(54 +) +(3,286 +) +Net cash used in investing activities +(904,065 +) +(449,341 +) +(437,276 +) +Cash flows from financing activities: +Purchases of treasury stock +(1,853 +) +(1,623 +) +(70,818 +) +Dividends paid +(30,796 +) +(30,681 +) +(92,865 +) +Tax benefit related to stock-based compensation +— +— +16,280 +Proceeds from long term debt +400,000 +— +— +Repayment of long term debt +(1,250 +) +— +— +Proceeds from borrowings under revolving credit facility +200,000 +— +— +Repayment of borrowings under revolving credit facility +(200,000 +) +— +(50,000 +) +Debt issuance costs +(10,779 +) +(6,169 +) +— +Proceeds from exercise of stock options +525 +569 +25,548 +Net cash provided by (used in) financing activities +355,847 +(37,904 +) +(171,855 +) +Effect of foreign exchange rate changes on cash +255 +2,222 +(2,084 +) +Net increase (decrease) in cash and cash equivalents +(22,265 +) +(31,346 +) +63,789 +Cash and cash equivalents at beginning of year +49,877 +81,223 +17,434 +Cash and cash equivalents at end of year +$ +27,612 +$ +49,877 +$ +81,223 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest expense, net of capitalized interest of $2,288 in 2010, +$0 in 2009 and $0 in 2008 +$ +— +$ +(1,804 +) +$ +(323 +) +Income taxes +115,666 +14,029 +(126,331 +) +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property +and equipment +$ +29,188 +$ +(25,110 +) +$ +(3,590 +) +Net (increase) decrease in deposits on equipment purchases +(50,170 +) +43,029 +(42,293 +) +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., through its wholly-owned subsidiaries (collectively +referred to herein as “Patterson-UTI” or the +“Company”), provides onshore contract drilling +services to major and independent oil and natural gas operators +primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +Pennsylvania, West Virginia and western Canada. The Company +provides pressure pumping services primarily in Texas and the +Appalachian Basin. The Company also owns and invests in oil and +natural gas assets as a working interest owner primarily in +Texas and New Mexico. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. Except for +wholly-owned subsidiaries, the Company has no controlling +financial interests in any other entity which would require +consolidation. +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 its functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed-contract method of accounting. The Company +follows the +percentage-of-completion +method of accounting for footage contract drilling arrangements. +Under the +percentage-of-completion +method, management estimates are relied upon in the +determination of the total estimated expenses to be incurred +drilling the well. Due to the nature of turnkey contract +drilling arrangements and the 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 as revenue reimbursements +received from third parties for +out-of-pocket +expenses and accounts for those +out-of-pocket +expenses as direct costs. Except for two wells drilled under +footage contracts in 2009, all of the wells the Company drilled +during the years ended December 31, 2010, 2009 and 2008 +were under daywork contracts. +Accounts receivable — Trade accounts receivable +are recorded at the invoiced amount. 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 at least quarterly. Significant individual +accounts receivable balances and balances which have been +outstanding greater than 90 days are reviewed individually +for collectibility. Account balances, when determined to be +uncollectible, are charged against the allowance. +Inventories — Inventories consist primarily of +sand and chemical products to be used in conjunction with the +Company’s pressure pumping activities. The inventories are +stated at the lower of cost or market, determined by the +first-in, +first-out method. +F-7 +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change +whenever equipment becomes idle. The estimated useful lives, in +years, are shown below: +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are +evaluated for impairment when certain triggering events or +changes in circumstances indicate that the carrying values may +not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and economic viability of the +respective projects. If no progress has been made in assessing +the reserves and economic viability of a project after one year +following the completion of drilling, the Company considers the +well costs to be impaired and recognizes the costs as expense. +Geological and geophysical costs, including seismic costs, and +costs to carry and retain undeveloped properties are charged to +expense when incurred. The capitalized costs of both +developmental and successful exploratory type wells, consisting +of lease and well equipment, lease acquisition costs and +intangible development costs, are depreciated, depleted and +amortized on the +units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves for each respective field. +The Company reviews its proved oil and natural gas properties +for impairment whenever a triggering event occurs, such as +downward revisions in reserve estimates or decreases in oil and +natural gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on +management’s expectation of future pricing over the lives +of the respective fields. These cash flow estimates are reviewed +by an independent petroleum engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment +expense is measured and recognized as the difference between net +book value and discounted cash flow. The discounted cash flow +estimates used in measuring impairment are based on +management’s expectations of future commodity prices over +the life of the respective field. The Company reviews unproved +oil and natural gas properties quarterly to assess potential +impairment. The Company’s impairment assessment is made on +a +lease-by-lease +basis and considers factors such as management’s intent to +drill, lease terms and abandonment of an area. If an unproved +property is determined to be impaired, the related property +costs are expensed. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. The +Company assesses impairment of its goodwill at least annually as +of December 31, or on an interim basis if events or +circumstances indicate that the fair value of goodwill may have +decreased below its carrying value. +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Disposals — Upon disposition of property and +equipment, the cost and related accumulated depreciation are +removed and any resulting gain or loss is reflected in the +consolidated statement of operations. +Net income (loss) per common share — The +Company provides a dual presentation of its net income (loss) +per common share in its consolidated statements of operations: +Basic net income (loss) per common share (“Basic EPS”) +and diluted net income (loss) per common share (“Diluted +EPS”). The Company adopted a new accounting standard on +January 1, 2009, which clarified that share-based payment +awards that entitle their holders to receive non-forfeitable +dividends before vesting should be considered participating +securities and, as such, should be included in the calculation +of +earnings-per-share +using the two-class method. All +earnings-per-share +data presented for the year ended December 31, 2008 have +been adjusted retrospectively to conform with this accounting +standard. +F-8 +The impact of this retrospective application to the year ended +December 31, 2008 was to reduce Basic EPS and Diluted EPS +by $0.01. +Basic EPS excludes dilution and is computed by first allocating +earnings between common stockholders and holders of non-vested +shares of restricted stock. Basic EPS is then determined by +dividing the earnings attributable to common stockholders by the +weighted average number of common shares outstanding during the +period, excluding non-vested shares of restricted stock. +Diluted EPS is based on the weighted average number of common +shares outstanding plus the dilutive effect of potential common +shares, including stock options, non-vested shares of restricted +stock and restricted stock units. The dilutive effect of stock +options and restricted stock units is determined using the +treasury stock method. The dilutive effect of non-vested shares +of restricted stock is based on the more dilutive of the +treasury stock method or the two-class method, assuming a +reallocation of undistributed earnings to common stockholders +after considering the dilutive effect of potential common shares +other than non-vested shares of restricted stock. +The following table presents information necessary to calculate +income (loss) from continuing operations per share, loss from +discontinued operations per share and net income (loss) per +share for the years ended December 31, 2010, 2009 and 2008, +as well as potentially dilutive securities excluded from the +weighted average number of diluted common shares outstanding +because their inclusion would have been anti-dilutive (in +thousands, except per share amounts): +2010 +2009 +2008 +BASIC EPS: +Income (loss) from continuing operations +$ +117,898 +$ +(33,960 +) +$ +353,868 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +(884 +) +313 +(3,279 +) +Income (loss) from continuing operations attributed to common +stockholders +$ +117,014 +$ +(33,647 +) +$ +350,589 +Loss from discontinued operations, net +$ +(956 +) +$ +(4,330 +) +$ +(6,799 +) +Adjust for loss attributed to holders of non-vested restricted +stock +7 +38 +64 +Loss from discontinued operations attributed to common +stockholders +$ +(949 +) +$ +(4,292 +) +$ +(6,735 +) +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,772 +152,069 +153,379 +Basic income (loss) from continuing operations per common share +$ +0.77 +$ +(0.22 +) +$ +2.29 +Basic loss from discontinued operations per common share +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Basic net income (loss) per common share +$ +0.76 +$ +(0.25 +) +$ +2.25 +F-9 +2010 +2009 +2008 +DILUTED EPS: +Income (loss) from continuing operations attributed to common +stockholders +$ +117,014 +$ +(33,647 +) +$ +350,589 +Add incremental earnings related to potential common shares +— +— +15 +Adjusted income (loss) from continuing operations attributed to +common stockholders +$ +117,014 +$ +(33,647 +) +$ +350,604 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,772 +152,069 +153,379 +Add dilutive effect of potential common shares +504 +— +979 +Weighted average number of diluted common shares outstanding +153,276 +152,069 +154,358 +Diluted income (loss) from continuing operations per common share +$ +0.76 +$ +(0.22 +) +$ +2.27 +Diluted loss from discontinued operations per common share +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Diluted net income (loss) per common share +$ +0.76 +$ +(0.25 +) +$ +2.23 +Potentially dilutive securities excluded as anti-dilutive +4,164 +8,090 +2,455 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. The Company’s policy is to account for +interest and penalties with respect to income taxes as operating +expenses. +Stock-based compensation — The Company +recognizes the cost of share-based payments under the +fair-value-based method. Under this method, compensation cost +related to share-based payments is measured based on the +estimated fair value of the awards at the date of grant, net of +estimated forfeitures. This expense is recognized over the +expected life of the awards (See Note 11). +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Recently Issued Accounting Standards — In June +2009, the FASB issued a new accounting standard that amends the +accounting and disclosure requirements for the consolidation of +variable interest entities. This new standard removes the +previously existing exception from applying consolidation +guidance to qualifying special-purpose entities and requires +ongoing reassessments of whether an enterprise is the primary +beneficiary of a variable interest entity. Prior to this new +standard, generally accepted accounting principles required +reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for the Company on January 1, +2010. The adoption of this standard did not impact the +Company’s consolidated financial statements. +In October 2009, the FASB issued a new accounting standard that +addresses the accounting for multiple-deliverable revenue +arrangements to enable vendors to account for deliverables +separately rather than as a combined unit. This new standard +addresses how to separate deliverables and how to measure and +allocate arrangement consideration to one or more units of +accounting. Existing accounting standards require a vendor to +use objective +F-10 +and reliable evidence of fair value for the undelivered items or +the residual method to separate deliverables in a +multiple-deliverable arrangement. Under the new standard, it is +expected that multiple-deliverable arrangements will be +separated in more circumstances than under current requirements. +The new standard establishes a hierarchy for determining the +selling price of a deliverable for purposes of allocating +revenue to multiple deliverables. The selling price used will be +based on vendor-specific objective evidence if available, +third-party evidence if vendor-specific objective evidence is +not available, or estimated selling price if neither +vendor-specific objective evidence nor third-party evidence is +available. The new standard must be prospectively applied to all +revenue arrangements entered into in fiscal years beginning on +or after June 15, 2010 and became effective for the Company +on January 1, 2011. The adoption of this standard is not +expected to have a material impact on the Company’s +consolidated financial position, results of operations or cash +flows. +In December 2010, the FASB issued an accounting standard update +that addresses the disclosure of supplementary pro forma +information for business combinations. This update clarifies +that when public entities are required to disclose pro forma +information for business combinations that occurred in the +current reporting period, the pro forma information should be +presented as if the business combination occurred as of the +beginning of the previous fiscal year when comparative financial +statements are presented. This update is effective prospectively +for business combinations for which the acquisition date is on +or after the beginning of the first annual reporting period +beginning on or after December 15, 2010. Early adoption is +permitted. The Company elected to early adopt this update and +this early adoption did not have an impact on the Company’s +consolidated financial position, results of operations or cash +flows. +Reclassifications — Certain reclassifications +have been made to the 2009 and 2008 consolidated financial +statements in order for them to conform with the 2010 +presentation. These reclassifications had no significant impact +on the Company’s financial position, results of operations +or cash flows. +2. +Discontinued +Operations +On January 27, 2011, the stock of the Company’s +electric wireline subsidiary, Universal Wireline, Inc., was sold +in a cash transaction for $25.5 million. Except for +inventory, the working capital of Universal Wireline, Inc. was +excluded from the sale and retained by a subsidiary of the +Company. Universal Wireline, Inc. was formed in 2010 to acquire +the electric wireline business of Key Energy Services, Inc., as +discussed in Note 3. The results of operations of this +business have been presented as results of discontinued +operations in these consolidated financial statements. As of +December 31, 2010, the assets to be disposed of were +classified as held for sale and are presented separately within +current assets under the caption “Assets held for +sale” in the consolidated balance sheet. Upon being +classified as held for sale, the assets to be disposed of were +recorded at fair value less estimated costs to sell resulting in +a charge of $2.2 million. Due to the fact that the carrying +value of the assets had been adjusted to net realizable value, +no significant additional gain or loss was recognized in +connection with the sale. +On January 20, 2010, the Company exited the drilling and +completion fluids business, which had previously been presented +as one of the Company’s reportable operating segments. On +that date, the Company’s wholly owned subsidiary, Ambar +Lone Star Fluids Services LLC, completed the sale of +substantially all of its assets, excluding billed accounts +receivable. The sales price was approximately +$42.6 million. Upon the Company’s exit from the +drilling and completion fluids business, the Company classified +its drilling and completion fluids operating segment as a +discontinued operation. Accordingly, the results of operations +of this business have been reclassified and presented as results +of discontinued operations for all periods presented in these +consolidated financial statements. As of December 31, 2009, +the assets to be disposed of were considered held for sale and +were presented separately within current assets under the +caption “Assets held for sale” in the consolidated +balance sheet. Upon being classified as held for sale, the +assets to be disposed of were adjusted to fair value less +estimated costs to sell resulting in an impairment loss of +$1.9 million. Due to the fact that the carrying value of +the assets had been adjusted to net realizable value, no +significant additional gain or loss was recognized in connection +with the sale in 2010. +F-11 +Summarized operating results from discontinued operations for +the years ended December 31, 2010, 2009 and 2008 are shown +below (in thousands): +2010 +2009 +2008 +Drilling and completion fluids revenues +$ +3,737 +$ +79,786 +$ +145,246 +Electric wireline revenues +5,712 +— +— +Operating revenues from discontinued operations +$ +9,449 +$ +79,786 +$ +145,246 +Loss before income taxes +$ +(1,499 +) +$ +(6,538 +) +$ +(4,410 +) +Income tax benefit (expense) +543 +2,208 +(2,389 +) +Loss from discontinued operations +$ +(956 +) +$ +(4,330 +) +$ +(6,799 +) +The loss before income taxes in 2008 includes approximately +$10.0 million in non-deductible charges resulting from the +impairment of goodwill. As a result, income tax expense was +incurred for the year despite the fact that the discontinued +operation had a pre-tax book loss. +The components of assets held for sale at December 31, 2010 +and 2009 are shown below (in thousands): +2010 +2009 +Assets held for sale: +Inventory +$ +756 +$ +28,620 +Unbilled accounts receivable +— +6,587 +Prepaid expenses and other current assets +— +324 +Property and equipment, net +24,769 +8,793 +Reserve to reduce disposal group to fair value less costs to sell +(2,155 +) +(1,900 +) +Total assets held for sale +$ +23,370 +$ +42,424 +3. +Acquisitions +On October 1, 2010, two subsidiaries of the Company, +Universal Pressure Pumping, Inc. and Universal Wireline, Inc., +completed the acquisition of certain assets from Key Energy +Pressure Pumping Services, LLC and Key Electric Wireline +Services, LLC relating to the businesses of providing pressure +pumping services and electric wireline services to participants +in the oil and natural gas industry. This acquisition expanded +the Company’s pressure pumping operations to additional +markets primarily in Texas. The aggregate purchase price was +$241 million consisting of a cash payment of +$238 million at closing funded through a combination of +cash on hand and a $200 million draw on the Company’s +revolving credit facility, a subsequent cash payment based on +the value of closing inventory of approximately +$1.2 million to be made in the first quarter of 2011 and +the assumption of liabilities of approximately +$2.1 million. The purchase price was allocated to the +tangible and identifiable intangible assets acquired and +liabilities assumed based on fair value. The tangible assets +acquired include property and equipment, inventories of sand and +chemicals on hand and repair and maintenance supplies on hand. +The identifiable intangible assets acquired include an agreement +by the seller to not compete for a period of three years and the +customer relationships in place at the time of the acquisition. +The liabilities assumed arose from pricing agreements in place +with certain customers that had pricing below current market +rates. A related deferred tax asset was recognized to reflect +the temporary difference associated with these below-market +pricing arrangements. The excess of the purchase price over the +fair values of the tangible assets, the identifiable intangible +assets and deferred +F-12 +tax asset, net of the liabilities assumed is recorded as +goodwill and was attributed to the pressure pumping business +acquired. A summary of the purchase price allocation follows (in +thousands): +Sand and chemical inventory +$ +6,848 +Supplies +312 +Property and equipment +154,359 +Non-compete agreement +1,400 +Customer relationships +25,500 +Deferred tax asset +8,514 +Goodwill +67,575 +Below-market pricing agreements +(23,200 +) +Total purchase price +$ +241,308 +In addition to the purchase price, acquisition-related expenses +associated with this transaction of approximately +$2.5 million were incurred by the Company and are presented +in the consolidated statement of operations under the caption +“acquisition-related expenses” for the year ended +December 31, 2010. These expenses include certain legal and +other professional fees directly related to the transaction, +fees incurred in connection with title transfers of the acquired +equipment and transition costs related to information technology. +As discussed in Note 2, the electric wireline business was +classified as held for sale at December 31, 2010 and was +subsequently sold on January 27, 2011. The results of +operations of the wireline business from the date of acquisition +included revenue of $5.7 million and a pre-tax operating +loss of $1.5 million (including a charge of approximately +$2.2 million incurred to reduce the carrying value of the +disposal group to its net realizable value) which is included in +loss from discontinued operations for the year ended +December 31, 2010. Results of operations of the acquired +pressure pumping business are included in the Company’s +consolidated results of operations from the date of acquisition. +Revenues of $84.7 million and income from operations of +$22.8 million from the acquired pressure pumping business +are included in the consolidated statement of operations for the +year ended December 31, 2010. +The following represents pro-forma unaudited financial +information for the years ended December 31, 2010 and 2009 as if +the acquisition had been completed on January 1, 2009 (in +thousands, except per share amounts): +2010 +2009 +(Unaudited) +Revenue +$ +1,660,635 +$ +905,168 +Income (loss) from continuing operations +$ +127,257 +$ +(46,807 +) +Net income (loss) +$ +126,301 +$ +(51,137 +) +Basic income (loss) from continuing operations per common share +$ +0.83 +$ +(0.33 +) +Basic net income (loss) per common share +$ +0.83 +$ +(0.36 +) +Diluted income (loss) from continuing operations per common share +$ +0.82 +$ +(0.33 +) +Diluted net income (loss) per common share +$ +0.82 +$ +(0.36 +) +F-13 +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2010 and 2009 (in thousands): +2010 +2009 +Equipment +$ +3,972,891 +$ +3,230,737 +Oil and natural gas properties +110,749 +93,354 +Buildings +61,425 +56,563 +Land +11,074 +9,795 +4,156,139 +3,390,449 +Less accumulated depreciation and depletion +(1,535,239 +) +(1,280,047 +) +Property and equipment, net +$ +2,620,900 +$ +2,110,402 +Depreciation, depletion, amortization and +impairment — The following table summarizes +depreciation, depletion, amortization and impairment expense +related to property and equipment and intangible assets for +2010, 2009 and 2008 (in millions): +2010 +2009 +2008 +Depreciation and impairment expense +$ +322.3 +$ +280.6 +$ +264.5 +Amortization expense +1.0 +— +— +Depletion expense +10.2 +9.2 +11.5 +Total +$ +333.5 +$ +289.8 +$ +276.0 +The Company evaluates the recoverability of its long-lived +assets whenever events or changes in circumstances indicate that +their carrying amounts may not be recoverable. In light of +adverse market conditions affecting the Company beginning in the +fourth quarter of 2008 and continuing into 2009, including a +substantial decrease in the operating levels of certain of its +business segments and a significant decline in oil and natural +gas commodity prices, the Company deemed it necessary to assess +the recoverability of long-lived assets within its contract +drilling segment in 2008. Due to a continued decrease in the +operating levels within its contract drilling business segment +through the first three quarters of 2009, the Company again +deemed it necessary to perform an impairment assessment of +long-lived assets in its contract drilling segment in 2009. In +light of the recent favorable trends in rig utilization and +revenue per operating day experienced by the Company and its +peers, management concluded that no triggering event had +occurred in 2010 with respect to its contract drilling segment. +With respect to the long-lived assets in the Company’s oil +and natural gas exploration and production segment, the Company +assesses the recoverability of long-lived assets at the end of +each quarter due to revisions in its oil and natural gas reserve +estimates and expectations about future commodity prices. The +Company concluded that its pressure pumping segment was not +subject to the negative events and trends to the same degree as +the contract drilling segment, and thus did not require further +assessment of recoverability in 2010, 2009 or 2008. +The Company performs the first step of its impairment +assessments by comparing the undiscounted cash flows for each +long-lived asset or asset group to its respective carrying +value. Based on the results of these impairment tests, the +carrying amounts of long-lived assets in the contract drilling +and oil and natural gas segments were determined to be +recoverable, except as described below. +The Company’s analysis indicated that the carrying amounts +of certain oil and natural gas properties were not recoverable +at various testing dates in 2010, 2009 and 2008. The +Company’s estimates of expected future net cash flows from +impaired properties are used in measuring the fair value of such +properties. The Company recorded impairment charges of $792,000, +$3.7 million and $4.4 million in 2010, 2009 and 2008, +respectively, related to its oil and natural gas properties. The +Company determined the fair value of the impaired assets using +internally developed unobservable inputs including future +pricing and reserves (level 3 inputs in the fair value +hierarchy of fair value accounting). +During 2010, 2009 and 2008, in connection with its long-term +planning process, the Company evaluated its then-current fleet +of marketable drilling rigs and identified four, 23 and 22 rigs, +respectively, that it determined +F-14 +would no longer be marketed as rigs. The components comprising +these rigs were evaluated, and those components with continuing +utility to the Company’s other marketed rigs were +transferred to other rigs or yards to be used as spare +equipment. The remaining components of these rigs were impaired +and the associated net book value of $4.2 million in 2010, +$10.5 million in 2009 and $10.4 million in 2008 was +expensed in the Company’s consolidated statements of +operations as an impairment charge. The impaired components were +estimated to have no fair value. +During 2010, the Company sold certain rights to explore and +develop zones deeper than depths that it generally targets for +certain of the oil and natural gas properties in which it has +working interests. The proceeds from this sale were +approximately $22.3 million and the sale resulted in a gain +on disposal of $20.1 million. +5. +Goodwill +and Intangible Assets +Goodwill — Goodwill by operating segment as of +December 31, 2010 and 2009 and changes for the years then +ended are as follows (in thousands): +2010 +2009 +Contract Drilling: +Balance as of January 1: +Goodwill +$ +86,234 +$ +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Changes to goodwill +— +— +Balance as of December 31: +Goodwill +86,234 +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Pressure Pumping: +Balance as of January 1: +Goodwill +— +— +Accumulated impairment losses +— +— +Goodwill recorded in connection with business combination +67,575 +— +Balance as of December 31: +Goodwill +67,575 +— +Accumulated impairment losses +— +— +67,575 +— +Total goodwill as of December 31 +$ +153,809 +$ +86,234 +Goodwill recorded in connection with a business combination in +2010 was a result of the Company’s acquisition of the +pressure pumping business of Key Energy Services, Inc. on +October 1, 2010, as discussed further in Note 3. +Approximately $53.2 million of this goodwill is expected to be +deductible for tax purposes. +Goodwill is evaluated at least annually on December 31 to +determine if the fair value of recorded goodwill has decreased +below its carrying value. For purposes of impairment testing, +goodwill is evaluated at the reporting unit level. The +Company’s reporting units for impairment testing have been +determined to be its operating segments. +The Company performed its annual goodwill impairment assessment +as of December 31, 2009 related to the $86.2 million +in goodwill recorded in its contract drilling reporting unit. In +completing its first step of the analysis, the Company used a +three-year projection of discounted cash flows, plus a terminal +value determined using the constant growth method to estimate +the fair value of the reporting unit. In developing this fair +value estimate, the Company applied key assumptions, including +an assumed discount rate of 15.42% and an assumed long-term +growth rate of 3.50%. Based +F-15 +on the results of the first step of the impairment test in 2009, +the Company concluded that no impairment was indicated in its +contract drilling reporting unit as the estimated fair value of +that reporting unit exceeded its carrying value. +The Company performed its annual goodwill impairment assessment +as of December 31, 2010. In completing its first step of +the analysis, the Company estimated its enterprise value based +on the market capitalization of the Company as determined by +reference to the closing price of the Company’s common +stock during the fifteen days before and after year end. The +enterprise value was allocated to the Company’s reporting +units and it was determined that the fair values of the +Company’s reporting units were in excess of their carrying +value. As a result, the Company concluded that no impairment of +goodwill was indicated as of December 31, 2010. +In the event that market conditions weaken, the Company may +determine additional impairments of goodwill in its contract +drilling or pressure pumping reporting units in the future, and +such impairment could be material. +Intangible Assets — Intangible assets were +recorded in the pressure pumping operating segment in connection +with the fourth quarter 2010 acquisition of the assets of the +pressure pumping business discussed in Note 3. As a result +of the purchase price allocation, the Company recorded +intangible assets related to a non-compete agreement and the +customer relationships acquired. These intangible assets were +recorded at fair value on the date of acquisition. +The non-compete agreement has a term of three years from +October 1, 2010. The value of this agreement was estimated +using a with and without scenario where cash flows were +projected through the term of the agreement assuming the +agreement is in place and compared to cash flows assuming the +non-compete agreement was not in place. The intangible asset +associated with the non-compete agreement is being amortized on +a straight-line basis over the three-year term of the agreement. +Amortization expense of $116,000 was recorded in the year ended +December 31, 2010 associated with the non-compete agreement. +The value of the customer relationships was estimated using a +multi-period excess earnings model to determine the present +value of the projected cash flows associated with the customers +in place at the time of the acquisition and taking into account +a contributory asset charge. The resulting intangible asset is +being amortized on a straight-line basis over seven years. +Amortization expense of $910,000 was recorded in the year ended +December 31, 2010 associated with customer relationships. +The following table sets forth the activity with respect to +intangible assets for the year ended December 31, 2010 (in +thousands): +Customer +Non-compete +Relationships +Total +Intangible assets at January 1, 2010 +$ +— +$ +— +$ +— +Intangible assets recognized at fair value in business +combination +1,400 +25,500 +26,900 +Amortization expense +(116 +) +(910 +) +(1,026 +) +Accumulated amortization at December 31, 2010 +(116 +) +(910 +) +(1,026 +) +Intangible assets, net at December 31, 2010 +$ +1,284 +$ +24,590 +$ +25,874 +F-16 +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2010 and 2009 (in thousands): +2010 +2009 +Salaries, wages, payroll taxes and benefits +$ +39,766 +$ +15,657 +Workers’ compensation liability +63,011 +65,825 +Sales, use and other taxes +6,782 +11,090 +Insurance, other than workers’ compensation +12,648 +12,498 +Deferred revenue — current +10,220 +— +Other +14,888 +3,680 +$ +147,315 +$ +108,750 +Deferred revenue was recorded in 2010 in the purchase price +allocation associated with the Company’s acquisition of a +pressure pumping business as discussed in Note 3. The +deferred revenue relates to +out-of-market +pricing agreements that were in place at the acquired business +at the time of the acquisition. The deferred revenue will be +recognized as pressure pumping revenue over the remaining term +of the pricing agreements. Deferred revenue of approximately +$6.1 million was recognized in the year ended +December 31, 2010 related to these pricing agreements. +7. +Asset +Retirement Obligation +The Company records a liability for the estimated costs to be +incurred in connection with the abandonment of oil and natural +gas properties in the future. This liability is included in the +caption “other” in the liabilities section of the +consolidated balance sheet. The following table describes the +changes to the Company’s asset retirement obligations +during 2010 and 2009 (in thousands): +2010 +2009 +Balance at beginning of year +$ +2,955 +$ +3,047 +Liabilities incurred +335 +157 +Liabilities settled +(339 +) +(354 +) +Accretion expense +112 +118 +Revision in estimated costs of plugging oil and natural gas wells +— +(13 +) +Asset retirement obligation at end of year +$ +3,063 +$ +2,955 +8. +Long Term +Debt +In March 2009, the Company entered into an unsecured revolving +credit facility (the “2009 Credit Facility”) with a +maximum borrowing capacity of $240 million. The Company +incurred debt issuance costs of approximately $6.2 million +during 2009 in connection with the 2009 Credit Facility. These +costs were being amortized to interest expense over the +contractual term of the 2009 Credit Facility. +On July 2, 2010, the Company entered into a +364-Day +Credit Agreement (the +“364-Day +Credit Agreement”) among the Company, as borrower, and +Wells Fargo Bank, N.A., as administrative agent and lender. The +364-Day +Credit Agreement was a committed senior unsecured single draw +term loan credit facility that permitted a borrowing of up to +$250 million, provided that the loan must have been drawn +no later than September 30, 2010 or, if an additional fee +was paid, October 30, 2010. The maturity date under the +364-Day +Credit Agreement was 364 days after the date on which the +closing conditions under the +364-Day +Credit Agreement were met. This facility was not drawn as of +September 30, 2010 and it expired at that time. +On August 19, 2010, the Company entered into a Credit +Agreement (the “2010 Credit Agreement”) among the +Company, as borrower, Wells Fargo Bank, N.A., as administrative +agent, letter of credit issuer, swing line lender and lender, +and each of the other letter of credit issuer and lender parties +thereto. The 2010 Credit Agreement is a +F-17 +committed senior unsecured credit facility that includes a +revolving credit facility and a term loan facility. The 2010 +Credit Agreement replaced the 2009 Credit Facility. +The revolving credit facility permits aggregate borrowings of up +to $400 million and contains a letter of credit facility +that is limited to $150 million and a swing line facility +that is limited to $40 million. Subject to customary +conditions, the Company may request that the lenders’ +aggregate commitments with respect to the revolving credit +facility be increased by up to $100 million, not to exceed +total commitments of $500 million. The maturity date for +the revolving facility is August 19, 2013. +The term loan facility provided for a loan of $100 million +which was funded on August 19, 2010. The term loan facility +is payable in quarterly principal installments commencing +November 19, 2010, and the installment amounts vary from +1.25% of the original principal amount for each of the first +four quarterly installments, 2.50% of the original principal +amount for each of the subsequent eight quarterly installments, +5.00% of the original principal amount for the next subsequent +three quarterly installments and the remainder is due at +maturity. The maturity date for the term loan facility is +August 19, 2014. +Loans under the 2010 Credit Agreement bear interest by +reference, at the Company’s election, to the LIBOR rate or +base rate. The applicable margin on LIBOR rate loans varies from +2.75% to 3.75% and the applicable margin on base rate loans +varies from 1.75% to 2.75%, in each case determined based upon +the Company’s debt to capitalization ratio. As of +December 31, 2010, the applicable margin on LIBOR rate +loans was 2.75% and the applicable margin on base rate loans was +1.75%. A letter of credit fee is payable by the Company equal to +the applicable margin for LIBOR rate loans times the daily +amount available to be drawn under outstanding letters of +credit. The commitment fee payable to the lenders for the unused +portion of the revolving credit facility varies from 0.50% to +0.75% based upon the Company’s debt to capitalization ratio +and was 0.50% as of December 31, 2010. +Each domestic subsidiary of the Company other than any +immaterial subsidiary has unconditionally guaranteed all +existing and future indebtedness and liabilities of the Company +and the other guarantors arising under the 2010 Credit Agreement +and other loan documents. Such guarantees also cover obligations +of the Company and any subsidiary of the Company arising under +any interest rate swap contract with any person while such +person is a lender or affiliate of a lender under the 2010 +Credit Agreement. +The 2010 Credit Agreement contains customary representations, +warranties, indemnities and affirmative and negative covenants. +The 2010 Credit Agreement also requires compliance with two +financial covenants. The Company must not permit its debt to +capitalization ratio to exceed 45% at any time. The 2010 Credit +Agreement generally defines the debt to capitalization ratio as +the ratio of (a) total borrowed money indebtedness to +(b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. The Company also must +not permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit +Agreement generally defines the interest coverage ratio as the +ratio of earnings before interest, taxes, depreciation and +amortization (“EBITDA”) of the four prior fiscal +quarters to interest charges for the same period. The Company +does not expect that the restrictions and covenants will impact +its ability to operate or react to opportunities that might +arise. +As of December 31, 2010, the Company had $98.8 million +principal amount outstanding under the term loan facility at an +interest rate of 3.125% and no borrowings outstanding under the +revolving credit facility. The Company had $41.2 million in +letters of credit outstanding at December 31, 2010 and, as +a result, had available borrowing capacity of approximately +$359 million at that date. +Senior Notes — On October 5, 2010, the +Company completed the issuance and sale of $300 million in +aggregate principal amount of its 4.97% Series A Senior +Notes due October 5, 2020 (the “Notes”) in a +private placement. A portion of the proceeds from the Notes was +used to repay a $200 million borrowing on the +Company’s revolving credit facility, which had been drawn +to fund a portion of the acquisition that closed on +October 1, 2010 as discussed in Note 3. The Notes are +senior unsecured obligations of the Company which rank equally +in right of payment with all other unsubordinated indebtedness +of the Company. The Notes are guaranteed on a senior unsecured +basis by each of the existing domestic subsidiaries of the +Company other than immaterial subsidiaries. +The Notes bear interest at a rate of 4.97% per annum and were +priced at 100% of the principal amount of the Notes. The Company +will pay interest on the Notes on April 5 and October 5 of each +year commencing on April 5, +F-18 +2011. The Notes will mature on October 5, 2020. The Notes +are prepayable at the Company’s option, in whole or in +part, provided that in the case of a partial prepayment, +prepayment must be in an amount not less than 5% of the +aggregate principal amount of the Notes then outstanding, at any +time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment +date, plus a “make-whole” premium as specified in the +note purchase agreement. The Company must offer to prepay the +Notes upon the occurrence of any change of control. In addition, +the Company must offer to prepay the Notes upon the occurrence +of certain asset dispositions if the proceeds therefrom are not +timely reinvested in productive assets. If any offer to prepay +is accepted, the purchase price of each prepaid Note is 100% of +the principal amount thereof, plus accrued and unpaid interest +thereon to the prepayment date. +The note purchase agreement requires compliance with two +financial covenants. The Company must not permit its debt to +capitalization ratio to exceed 50% at any time. The note +purchase agreement generally defines the debt to capitalization +ratio as the ratio of (a) total borrowed money indebtedness +to (b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. The Company also must +not permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 2.50 to 1.00. The note purchase +agreement generally defines the interest coverage ratio as the +ratio for the four prior quarters of EBITDA to interest charges +for that same period. The Company does not expect that the +restrictions and covenants will impair its ability to operate or +react to opportunities that might arise. +Events of default under the note purchase agreement include +failure to pay principal or interest when due, failure to comply +with the financial and operational covenants, a cross default +event, a judgment in excess of a threshold event, the guaranty +agreement ceasing to be enforceable, the occurrence of certain +ERISA events, a change of control event and bankruptcy and other +insolvency events. If an event of default occurs and is +continuing, then holders of a majority in principal amount of +the Notes have the right to declare all the Notes +then-outstanding to be immediately due and payable. In addition, +if the Company defaults in payments on any Note, then until such +defaults are cured, the holder thereof may declare all the Notes +held by it to be immediately due and payable. +During the year ended December 31, 2010, the Company +incurred approximately $10.8 million in debt issuance costs +in connection with the 2010 Credit Agreement and the Senior +Notes discussed above. These costs were deferred and will be +recognized as interest expense over the term of the underlying +debt. For the year ended December 31, 2010, interest +expense related to the amortization of debt issuance costs for +the 2010 Credit Agreement and the Senior Notes was approximately +$1.1 million. +Presented below is a schedule of the principal repayment +requirements of long-term debt by fiscal year as of +December 31, 2010 (in thousands): +Year ending December 31, +2011 +$ +6,250 +2012 +10,000 +2013 +12,500 +2014 +70,000 +2015 +— +Thereafter +300,000 +Total +$ +398,750 +9. +Commitments, +Contingencies and Other Matters +Commitments — As of December 31, 2010, the +Company maintained letters of credit in the aggregate amount of +$41.2 million for the benefit of various insurance +companies as collateral for retrospective premiums and retained +losses which could become payable under the terms of the +underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically +renewed. As of December 31, 2010, no amounts had been drawn +under the letters of credit. +As of December 31, 2010, the Company had commitments to +purchase approximately $267 million of major equipment. +F-19 +Contingencies — The Company’s contract +services operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in +personal injury or death, suspended drilling operations, damage +to, or destruction of equipment, damage to producing formations +and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains, +subject to a $2.0 million self-insured retention, general +liability insurance coverage, with $10.0 million of +aggregate coverage and excess liability and umbrella coverages +up to $200 million per occurrence and in the aggregate. The +Company maintains a $1.0 million per occurrence deductible +on its workers’ compensation, and automobile liability +insurance coverages. Accrued expenses related to insurance +claims are set forth in Note 6. +The Company believes it is adequately insured for bodily injury +and property damage to others with respect to its operations. +However, such insurance may not be sufficient to protect the +Company against liability for all consequences of personal +injury, well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its equipment. However, it does +not cover the full replacement cost of the equipment and the +Company does not carry insurance against loss of earnings +resulting from such damage. There can be no assurance that such +insurance coverage will always be available on terms that are +satisfactory to the Company, if at all. +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic +twelve-month renewals unless the Company notifies the Key +Employee at least ninety days before the end of such renewal +period that the term will not be extended. If a change in +control of the Company occurs during the term of the agreement +and the Key Employee’s employment is terminated (i) by +the Company other than for cause or other than automatically as +a result of death, disability or retirement, or (ii) by the +Key Employee for good reason (as those terms are defined in the +Change in Control Agreements), then the Key Employee shall +generally be entitled to, among other things: +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +F-20 +10. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2008, 2009 +and 2010 as follows: +Per Share +Total +(in thousands) +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +2010: +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +On February 2, 2011, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.05 per share to be paid on March 30, 2011 to holders of +record as of March 15, 2011. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors +approved a stock buyback program authorizing purchases of up to +$250 million of the Company’s common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2008, the Company purchased +3,502,047 shares of its common stock under the program at a +cost of approximately $66.3 million. During the year ended +December 31, 2009, the Company purchased 5,715 shares +of its common stock under the program at a cost of approximately +$79,000. During the year ended December 31, 2010, the +Company purchased 8,743 shares of its common stock under +the program at a cost of approximately $123,000. As of +December 31, 2010, the Company is authorized to purchase +approximately $113 million of the Company’s +outstanding common stock under the program. Shares purchased +under the program are accounted for as treasury stock. +The Company purchased 117,083, 114,983 and 152,235 shares +of treasury stock from employees during 2010, 2009 and 2008, +respectively. These shares were purchased at fair market value +upon the vesting of restricted stock to provide the employees +with the funds necessary to satisfy payroll tax withholding +obligations. The total purchase price for these shares was +approximately $1.7 million, $1.5 million and +$4.5 million in 2010, 2009 and 2008, respectively. These +purchases were made pursuant to the terms of the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to +the stock buyback program. +F-21 +11. +Stock-based +Compensation +The Company uses share-based payments to compensate employees +and non-employee directors. The Company recognizes the cost of +share-based payments under the fair-value-based method. +Share-based awards consist of equity instruments in the form of +stock options, restricted stock or restricted stock units and +have included service and, in certain cases, performance +conditions. The Company’s share-based awards also include +both cash-settled and share-settled performance unit awards. +Cash-settled performance unit awards are accounted for as +liability awards. Share-settled performance unit awards are +accounted for as equity awards. The Company issues shares of +common stock when vested stock options are exercised, when +restricted stock is granted and when restricted stock units and +share-settled performance unit awards vest. +The Company’s shareholders have approved the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 +Plan”), and the Board of Directors adopted a resolution +that no future grants would be made under any of the +Company’s other previously existing plans. During 2010, the +Company amended the 2005 Plan to, among other things, increase +the total number of shares authorized for grant from 10,250,000 +to 15,250,000. The Company’s share-based compensation plans +at December 31, 2010 follow: +Shares +Shares +Authorized +Awards +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended +15,250,000 +5,830,135 +5,763,314 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +2,843,300 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +168,552 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over one year for non-employee +directors and three to four years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2010, +non-incentive stock options, restricted stock awards, restricted +stock units and performance unit awards had been granted under +the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Stock Options — The Company estimates the grant +date fair values of stock options using the Black-Scholes-Merton +valuation model. Volatility assumptions are based on the +historic volatility of the Company’s common stock over the +most recent period equal to the expected term of the options as +of the date the options are granted. The expected term +assumptions are based on the Company’s experience with +respect to employee stock option activity. +F-22 +Dividend yield assumptions are based on the expected dividends +at the time the options are granted. The risk-free interest rate +assumptions are determined by reference to United States +Treasury yields. Weighted-average assumptions used to estimate +grant date fair values for stock options granted in the years +ended December 31, 2010, 2009 and 2008 follow: +2010 +2009 +2008 +Volatility +45.98 +% +49.90 +% +37.04 +% +Expected term (in years) +5.00 +4.00 +4.17 +Dividend yield +1.35 +% +1.67 +% +2.27 +% +Risk-free interest rate +2.47 +% +1.67 +% +2.91 +% +Stock option activity for the year ended December 31, 2010 +follows: +Weighted-average +Shares +exercise price +Outstanding at beginning of year +6,841,770 +$ +20.17 +Granted +1,016,250 +$ +14.85 +Exercised +(60,918 +) +$ +8.61 +Cancelled +(10,000 +) +$ +13.17 +Expired +(77,000 +) +$ +19.46 +Outstanding at end of year +7,710,102 +$ +19.58 +Exercisable at end of year +6,095,018 +$ +20.81 +Options outstanding at December 31, 2010 have an aggregate +intrinsic value of approximately $30.0 million and a +weighted-average remaining contractual term of 5.6 years. +Options exercisable at December 31, 2010 have an aggregate +intrinsic value of approximately $18.7 million and a +weighted-average remaining contractual term of 4.8 years. +Additional information with respect to options granted, vested +and exercised during the years ended December 31, 2010, +2009 and 2008 follows: +2010 +2009 +2008 +Weighted-average grant date fair value of stock options granted +(per share) +$ +5.69 +$ +4.71 +$ +7.20 +Grant date fair value of stock options vested during the year +(in thousands) +$ +5,553 +$ +6,973 +$ +6,761 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +523 +$ +510 +$ +45,240 +As of December 31, 2010, options to purchase +1,615,084 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2010 with respect +to these non-vested options follows: +Aggregate intrinsic value +$11.3 million +Weighted-average remaining contractual term +8.88 years +Weighted-average remaining expected term +3.56 years +Weighted-average remaining vesting period +1.88 years +Unrecognized compensation cost +$7.1 million +Restricted Stock — For all restricted stock +awards to date, shares of common stock were issued when the +awards were made. Non-vested shares are subject to forfeiture +for failure to fulfill service conditions and, in certain cases, +performance conditions. Non- forfeitable dividends are paid on +non-vested shares of restricted stock. The Company uses the +straight-line method to recognize periodic compensation cost +over the vesting period. +F-23 +Restricted stock activity for the year ended December 31, +2010 follows: +Weighted- +average +Grant Date +Shares +Fair Value +Non-vested restricted stock outstanding at beginning of year +1,231,901 +$ +21.67 +Granted +699,825 +$ +14.68 +Vested +(758,394 +) +$ +23.48 +Forfeited +(59,281 +) +$ +21.63 +Non-vested restricted stock outstanding at end of year +1,114,051 +$ +16.05 +As of December 31, 2010, approximately 976,000 shares +of non-vested restricted stock outstanding are expected to vest. +Additional information as of December 31, 2010 with respect +to these non-vested shares follows: +Aggregate intrinsic value +$21.0 million +Weighted-average remaining vesting period +1.90 years +Unrecognized compensation cost +$12.2 million +Restricted Stock Units — For all restricted +stock unit awards made to date, shares of common stock are not +issued until the units vest. Restricted stock units are subject +to forfeiture for failure to fulfill service conditions. +Non-forfeitable cash dividend equivalents are paid on non-vested +restricted stock units. +Restricted stock unit activity for the year ended +December 31, 2010 follows: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock units outstanding at beginning of +year +16,167 +$ +26.81 +Granted +9,000 +$ +13.81 +Vested +(7,333 +) +$ +28.08 +Forfeited +— +$ +— +Non-vested restricted stock units outstanding at end of year +17,834 +$ +19.73 +Performance Unit Awards. On April 28, +2009, the Company granted cash-settled performance unit awards +to certain executive officers (the “2009 Performance +Units”). The 2009 Performance Units provide for those +executive officers to receive a cash payment upon the +achievement of certain performance goals established by the +Company during a specified period. The performance period for +the 2009 Performance Units is the period from April 1, 2009 +through March 31, 2012, but can extend through +March 31, 2014 in certain circumstances. The performance +goals for the 2009 Performance Units are tied to the +Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee of the Board of +Directors. These goals are considered to be market conditions +under the relevant accounting standards and the market +conditions are factored into the determination of the fair value +of the performance units. Generally, the recipients will receive +a base payment if the Company’s total shareholder return is +positive and, when compared to the peer group, is at or above +the 25 th +percentile but less than the +50 th +percentile; two times the base if at or above the 50th +percentile but less than the +75 th +percentile, and four times the base if at the 75th percentile or +higher. The total base amount with respect to the 2009 +Performance Units is approximately $1.7 million. Because +the 2009 Performance Units are to be settled in cash at the end +of the performance period, they are accounted for as liability +awards and the Company’s pro-rated obligation is measured +at estimated fair value at the end of each reporting period +using a Monte Carlo simulation model. As of December 31, +2010 this pro-rated obligation was approximately +$2.3 million and is included in the caption +“other” in the liabilities section of the consolidated +balance sheet. Compensation expense associated with the 2009 +Performance Units was approximately $1.5 million and +$859,000 for the years ended December 31,2010 and 2009, +respectively. +F-24 +On April 27, 2010, the Company granted stock-settled +performance unit awards to certain executive officers (the +“2010 Performance Units”). The 2010 Performance Units +provide for those executive officers to receive a grant of +shares of stock upon the achievement of certain performance +goals established by the Company during a specified period. The +performance period for the 2010 Performance Units is the period +from April 1, 2010 through March 31, 2013, but can +extend through March 31, 2015 in certain circumstances. The +performance goals for the 2010 Performance Units are tied to the +Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee of the Board of +Directors. These goals are considered to be market conditions +under the relevant accounting standards and the market +conditions are factored into the determination of the fair value +of the performance units. Generally, the recipients will receive +a base number of shares if the Company’s total shareholder +return is positive and, when compared to the peer group, is at +or above the 25th percentile but less than the 50th percentile, +two times the base if at or above the 50th percentile but less +than the 75th percentile, and four times the base if at the 75th +percentile or higher. The grant of shares when achievement is +between the 25th and 75th percentile will be determined on a +pro-rata basis. The total base number of shares with respect to +the 2010 Performance Units is 89,375 shares. Because the +2010 Performance Units are stock-settled awards, they are +accounted for as equity awards and measured at fair value on the +date of grant. The fair value of the 2010 Performance Units as +of the date of grant was approximately $3.1 million using a +Monte Carlo simulation model. This amount will be recognized on +a straight-line basis over the performance period. Compensation +expense associated with the 2010 Performance Units was +approximately $779,000 for the year ended December 31, 2010. +Dividends on Equity Awards — Non-forfeitable +cash dividends and dividend equivalents paid on equity awards +are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of restricted stock awards expected to vest. +• +Dividends are recognized as additional compensation cost for the +portion of restricted stock awards that are not expected to vest +or that ultimately do not vest. +• +Dividend equivalents are recognized as additional compensation +cost for restricted stock units. +12. +Leases +The Company incurred rent expense of $18.1 million, +$11.9 million and $31.5 million for the years 2010, +2009 and 2008, respectively. Rent expense is primarily related +to short-term equipment rentals that are generally passed +through to customers. The Company’s obligations under +non-cancelable operating lease agreements are not material to +its operations or cash flows. +F-25 +13. +Income +Taxes +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2010, 2009 and 2008 are as follows (in +thousands): +2010 +2009 +2008 +Federal income tax expense (benefit): +Current +$ +(77,310 +) +$ +(117,493 +) +$ +117,367 +Deferred +145,198 +103,574 +57,879 +67,888 +(13,919 +) +175,246 +State income tax expense (benefit): +Current +19 +(1,883 +) +6,475 +Deferred +3,246 +(1,875 +) +7,070 +3,265 +(3,758 +) +13,545 +Foreign income tax expense (benefit): +Current +2,657 +338 +4,256 +Deferred +(954 +) +(256 +) +443 +1,703 +82 +4,699 +Total income tax expense (benefit): +Current +(74,634 +) +(119,038 +) +128,098 +Deferred +147,490 +101,443 +65,392 +Total income tax expense (benefit) +$ +72,856 +$ +(17,595 +) +$ +193,490 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2010, 2009 and 2008 is summarized as follows: +2010 +2009 +2008 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.1 +4.7 +1.7 +Permanent differences +2.3 +(5.7 +) +(1.2 +) +Other, net +(0.2 +) +0.1 +(0.2 +) +Effective tax rate +38.2 +% +34.1 +% +35.3 +% +For 2008, the permanent difference indicated above was largely +attributable to the Company’s Domestic Production +Activities Deduction. The Domestic Production Activities +Deduction was enacted as part of the American Jobs Creation Act +of 2004 (as revised by the Emergency Economic Stabilization Act +of 2008,) and allows a deduction of 6% in both 2008 and 2009 and +9% in 2010 and thereafter on the lesser of qualified production +activities income or taxable income. The permanent differences +for 2010 and 2009 reflect the recapture of a portion of this +deduction due to the planned carryback of the 2010 net +operating loss to prior years and the carryback of the 2009 net +operating loss to prior years. This recapture resulted in a +negative effective rate impact in 2009 due to the Company having +a loss before income taxes in that year. +F-26 +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +December 31, +2010 +Change +2009 +Change +2008 +Change +2007 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +— +$ +— +$ +— +$ +— +$ +— +$ +(374 +) +$ +374 +Workers’ compensation allowance +23,290 +(1,334 +) +24,624 +(1,360 +) +25,984 +(602 +) +26,586 +Other +18,654 +(962 +) +19,616 +(2,735 +) +22,351 +3,287 +19,064 +41,944 +(2,296 +) +44,240 +(4,095 +) +48,335 +2,311 +46,024 +Non-current: +Net operating loss carryforwards +6,465 +1,593 +4,872 +4,872 +— +— +— +AMT credit +— +— +— +— +— +(118 +) +118 +Expense associated with employee stock options +11,252 +2,123 +9,129 +2,500 +6,629 +1,381 +5,248 +Federal benefit of foreign deferred tax liabilities +— +(9,160 +) +9,160 +(256 +) +9,416 +443 +8,973 +Federal benefit of state deferred tax liabilities +13,155 +3,383 +9,772 +2,702 +7,070 +1,643 +5,427 +Other +16,031 +6,546 +9,485 +4,120 +5,365 +614 +4,751 +46,903 +4,485 +42,418 +13,938 +28,480 +3,963 +24,517 +Total deferred tax assets +88,847 +2,189 +86,658 +9,843 +76,815 +6,274 +70,541 +Deferred tax liabilities: +Current: +Other +(15,129 +) +(3,766 +) +(11,363 +) +1,044 +(12,407 +) +(1,753 +) +(10,654 +) +Non-current: +Property and equipment basis difference +(546,655 +) +(133,542 +) +(413,113 +) +(110,786 +) +(302,327 +) +(70,362 +) +(231,965 +) +Other +(11,670 +) +(709 +) +(10,961 +) +(7,091 +) +(3,870 +) +8,172 +(12,042 +) +(558,325 +) +(134,251 +) +(424,074 +) +(117,877 +) +(306,197 +) +(62,190 +) +(244,007 +) +Total deferred tax liabilities +(573,454 +) +(138,017 +) +(435,437 +) +(116,833 +) +(318,604 +) +(63,943 +) +(254,661 +) +Net deferred tax liability +$ +(484,607 +) +$ +(135,828 +) +$ +(348,779 +) +$ +(106,990 +) +$ +(241,789 +) +$ +(57,669 +) +$ +(184,120 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2010 and +2009 to be realized as a result of the reversal of existing +taxable temporary differences giving rise to deferred tax +liabilities and the generation of taxable income; therefore, no +valuation allowance is considered necessary. +Other deferred tax assets consist primarily of the tax effect of +various allowance accounts and tax-deferred expenses expected to +generate future tax benefit of approximately $35 million. +Other deferred tax liabilities consist primarily of the tax +effect of receivables from insurance companies and tax-deferred +income not yet recognized for tax purposes. +For income tax purposes, the Company generated approximately +$221 million of Federal net operating losses and +approximately $71.3 million of state net operating losses +during the year ended December 31, 2010. Of these amounts, +approximately $257 million will be carried back to prior +years, and the remaining balance can be carried +F-27 +forward to future years. Net operating losses that can be +carried forward, if unused, are scheduled to expire as follows: +2014 — $9 million; 2015 — +$5 million; 2019 — $12 million; +2029 — $57 million and 2030 - $18 million. +As of December 31, 2010, the Company had no unrecognized +tax benefits. The Company has established a policy to account +for interest and penalties related to uncertain income tax +positions as operating expenses. As of December 31, 2010, +the tax years ended December 31, 2007 through +December 31, 2009 are open for examination by +U.S. taxing authorities. As of December 31, 2010, the +tax years ended December 31, 2006 through December 31, +2009 are open for examination by Canadian taxing authorities. +On January 1, 2010, the Company converted its Canadian +operations from a Canadian branch to a controlled foreign +corporation for Federal income tax purposes. Because the +statutory tax rates in Canada are lower than those in the United +States, this transaction triggered a $5.1 million reduction +in deferred tax liabilities, which is being amortized as a +reduction to deferred income tax expense over the weighted +average remaining useful life of the Canadian assets. +As a result of the above conversion, the Company’s Canadian +assets are no longer subject to United States taxation, provided +that the related unremitted earnings are permanently reinvested +in Canada. Effective January 1, 2010, the Company has +elected to permanently reinvest these unremitted earnings in +Canada, and intends to do so for the foreseeable future. As a +result, no deferred United States Federal or state income taxes +have been provided on such unremitted foreign earnings, which +totaled approximately $6.3 million as of December 31, +2010. +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $3.1 million in 2010, $2.8 million in +2009 and $4.5 million in 2008 for the Company’s cash +contributions to the plan. +15. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to three business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services and (iii) the +investment, on a working interest basis, in oil and natural gas +properties. Each of these segments represents a distinct type of +business. These segments have separate management teams which +report to the Company’s chief operating decision maker. The +results of operations in these segments are regularly reviewed +by the chief operating decision maker for purposes of +determining resource allocation and assessing performance. As +discussed in Note 2, in January 2010 the Company exited the +drilling and completion fluids services business which +previously was reported as a business segment. Operating results +for that business for the years ended December 31, 2010, +2009 and 2008 are presented as discontinued operations in the +consolidated statements of operations. Also included in +discontinued operations for the year ended December 31, +2010 are the operating results for an electric wireline business +that was acquired on October 1, 2010 and sold in January +2011. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2010, the Company +had 356 marketable land-based drilling rigs, of which 73 of the +drilling rigs were based in west Texas and southeastern New +Mexico; 97 in north central and east Texas, northern Louisiana +and Mississippi; 58 in the Rocky Mountain region (Colorado, +Utah, Wyoming, Montana and North Dakota); 51 in south Texas and +southern Louisiana; 32 in the Texas panhandle, Oklahoma and +Arkansas; 25 in the Appalachian Basin and 20 in western Canada. +For the years ended December 31, 2010, 2009 and 2008, +contract drilling revenue earned in Canada was +$65.7 million, $45.4 million and $88.5 million, +respectively. Additionally, long-lived assets within the +contract drilling segment located in Canada totalled +$70.7 million and $69.2 million as of +December 31, 2010 and 2009, respectively. +Pressure Pumping — The Company provides +pressure pumping services to oil and natural gas operators +primarily in Texas and the Appalachian Basin. Pressure pumping +services are primarily well stimulation and cementing for the +completion of new wells and remedial work on existing wells. +Well stimulation involves processes inside a well designed to +enhance the flow of oil, natural gas, or other desired +substances from the well. +F-28 +Cementing is the process of inserting material between the hole +and the pipe to center and stabilize the pipe in the hole. +Oil and Natural Gas — The Company owns and +invests in oil and natural gas assets as a working interest +owner. The Company’s oil and natural gas interests are +located primarily in Texas and New Mexico. +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Revenues: +Contract drilling +$ +1,085,722 +$ +600,423 +$ +1,808,600 +Pressure pumping +350,608 +161,441 +217,494 +Oil and natural gas +30,425 +21,218 +42,360 +Total segment revenues +1,466,755 +783,082 +2,068,454 +Elimination of intercompany revenues(a) +(3,824 +) +(1,136 +) +(4,574 +) +Total revenues +$ +1,462,931 +$ +781,946 +$ +2,063,880 +Income (loss) from continuing operations before income taxes: +Contract drilling +$ +140,483 +$ +(11,219 +) +$ +520,636 +Pressure pumping +62,194 +1,017 +42,019 +Oil and natural gas +12,455 +950 +13,711 +215,132 +(9,252 +) +576,366 +Corporate and other +(37,019 +) +(35,577 +) +(34,596 +) +Net (loss) gain on asset disposals(b) +22,812 +(3,385 +) +4,163 +Interest income +1,674 +381 +1,553 +Interest expense +(12,772 +) +(4,148 +) +(630 +) +Other +927 +426 +502 +Income (loss) from continuing operations before income taxes +$ +190,754 +$ +(51,555 +) +$ +547,358 +Identifiable assets: +Contract drilling +$ +2,678,250 +$ +2,129,567 +$ +2,255,421 +Pressure pumping +533,597 +213,094 +210,805 +Oil and natural gas +36,508 +25,355 +31,760 +Corporate and other(c) +174,676 +294,136 +214,831 +Total assets +$ +3,423,031 +$ +2,662,152 +$ +2,712,817 +Depreciation, depletion, amortization and impairment: +Contract drilling +$ +280,458 +$ +248,424 +$ +239,700 +Pressure pumping +40,724 +27,589 +19,600 +Oil and natural gas +10,950 +12,927 +15,856 +Corporate and other +1,361 +907 +834 +Total depreciation, depletion, amortization and impairment +$ +333,493 +$ +289,847 +$ +275,990 +F-29 +Years Ended December 31, +2010 +2009 +2008 +Capital expenditures: +Contract drilling +$ +655,550 +$ +395,376 +$ +360,645 +Pressure pumping +51,064 +43,144 +61,289 +Oil and natural gas +23,067 +7,341 +22,981 +Corporate and other +8,409 +6,785 +511 +Total capital expenditures +$ +738,090 +$ +452,646 +$ +445,426 +(a) +Includes contract drilling intercompany revenues related to +drilling services provided to the oil and natural gas +exploration and production segment. +(b) +Net gains or losses associated with the disposal of assets +relate to corporate strategy decisions of the executive +management group. Accordingly, the related gains or losses have +been separately presented and excluded from the results of +specific segments. +(c) +Corporate and other assets primarily include identifiable assets +associated with assets held for sale as well as cash on hand, +income taxes receivable and certain deferred Federal income tax +assets. +16. +Concentrations +of Credit Risk +Financial instruments which potentially subject the Company to +concentrations of credit risk consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial +institutions. At December 31, 2010 and 2009, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2010 +2009 +Deposits in FDIC and SIPC-insured institutions under insurance +limits +$ +1,523 +$ +20,543 +Deposits in FDIC and SIPC-insured institutions over insurance +limits +51,625 +47,376 +Deposits in foreign banks +11,533 +4,383 +64,681 +72,302 +Less outstanding checks and other reconciling items +(37,069 +) +(22,425 +) +Cash and cash equivalents +$ +27,612 +$ +49,877 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2010, 2009 or 2008. The Company recorded a +provision for bad debts for 2010, 2009 and 2008 of +$(2.0) million, $3.8 million and $4.4 million, +respectively. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. The carrying value of +the balance outstanding under the term loan facility at +December 31, 2010 approximates fair value as it has a +floating interest rate that adjusts at each quarterly interest +payment date. The fair value of the 4.97% Series A Senior +Notes at December 31, 2010 was approximately +$290 million. +F-30 +17. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2009 +Operating revenues +$ +268,209 +$ +140,497 +$ +159,671 +$ +213,569 +Operating income (loss) +25,154 +(25,855 +) +(24,619 +) +(22,894 +) +Income (loss) from continuing operations, net of income taxes +15,835 +(16,891 +) +(16,814 +) +(16,090 +) +Income (loss) from discontinued operations, net of income taxes +368 +(852 +) +(1,766 +) +(2,080 +) +Net income (loss) +16,203 +(17,743 +) +(18,580 +) +(18,170 +) +Basic income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income +$ +0.11 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +Diluted income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income +$ +0.11 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +2010 +Operating revenues +$ +271,598 +$ +306,992 +$ +378,663 +$ +505,678 +Operating income +7,831 +45,757 +52,509 +94,828 +Income (loss) from continuing operations, net of income taxes +4,186 +29,528 +29,374 +54,810 +Loss from discontinued operations, net of income taxes +— +— +— +(956 +) +Net income +4,186 +29,528 +29,374 +53,854 +Basic income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.36 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +Diluted income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +As discussed in Note 2, the Company exited the drilling and +completion fluids services business in January 2010 and sold a +recently acquired wireline business in January 2011. The results +of operations related to those businesses have been reclassified +and presented as discontinued operations in the quarterly +financial information above. +F-31 +Schedule +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND +QUALIFYING ACCOUNTS +Charged to +Beginning +Costs and +Ending +Description +Balance +Expenses +Deductions(1) +Balance +(In thousands) +Year Ended December 31, 2010 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,911 +$ +(2,000 +) +$ +3,797 +$ +5,114 +Year Ended December 31, 2009 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +9,330 +$ +4,700 +$ +3,119 +$ +10,911 +Year Ended December 31, 2008 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,014 +$ +4,350 +$ +5,034 +$ +9,330 +(1) +Consists of uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 14, 2011 +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 +February 14, 2011. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +EXHIBIT INDEX +2 +.1 +Asset Purchase Agreement dated July 2, 2010 by and among +Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a +Universal Pressure Pumping, Inc.), Key Energy Pressure Pumping +Services, LLC, Key Electric Wireline Services, LLC and Key +Energy Services, Inc. (filed July 6, 2010 as +Exhibit 2.1 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +2 +.2 +Letter Agreement dated September 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.2 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +2 +.3 +Letter Agreement dated October 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned to REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.6 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.8 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.9 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.10 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.11 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.12 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.13 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.1 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.14 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed April 27, 2010 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.15 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.3 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.16 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time (filed February 19, 2010 as +Exhibit 10.9 to the Company’s Annual Report on +Form 10-K +for the year ended December 31, 2009 and incorporated +herein by reference).* +10 +.17 +Form of Amendment to Cash-Settled Performance Unit Award +Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended March 31, 2010 and +incorporated herein by reference).* +10 +.18 +Form of Share-Settled Performance Unit Award Agreement under the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed +August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2010 and +incorporated herein by reference).* +10 +.19 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +10 +.27 +Credit Agreement dated August 19, 2010, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer and lender and +each of the other letter of credit issuer and lender parties +thereto (filed August 19, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.28 +Note Purchase Agreement dated October 5, 2010 by and among +Patterson-UTI Energy, Inc. and the purchasers named therein +(filed October 6, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2010, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Income, (iii) the Consolidated Statements of +Changes in Stockholders’ Equity, (iv) the Consolidated +Statements of Cash Flows, and (v) Notes to Consolidated +Financial Statements, tagged as blocks of text. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/filing_metadata.csv b/raw/filings/0000889900/2010/0000950123-11-013816/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..41509c51a4d01b0c65d7df64f3bb27cd5ded4d32 --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2011-02-14,2010-12-31,2011-02-15T00:24:05.000Z,0000950123-11-013816,d78488e10vk.htm,FORM 10-K,5059540,1,0,https://www.sec.gov/Archives/edgar/data/889900/000095012311013816/d78488e10vk.htm,https://www.sec.gov/Archives/edgar/data/889900/000095012311013816/,2010,2010,1 diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/item1.txt b/raw/filings/0000889900/2010/0000950123-11-013816/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..283c20b4a904f63fa5b4655af5d14f9e4ebd5337 --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/item1.txt @@ -0,0 +1,605 @@ +Item 1. +Business +Available +Information +This Report, along with our Quarterly Reports on +Form 10-Q, +Current Reports on +Form 8-K +and amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Exchange Act, are available +free of charge through our Internet website +( www.patenergy.com ) as soon as reasonably practicable +after we electronically file such material with, or furnish it +to, the SEC. The information contained on our website is not +part of this Report or other filings that we make with the SEC. +You may read and copy any materials we file with the SEC at the +SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the +operation of the Public Reference Room by calling the SEC at +1-800-SEC-0330. +The SEC maintains an internet site ( www.sec.gov ) that +contains reports, proxy and information statements and other +information regarding issuers that file electronically with the +SEC. +1 +Overview +We own and operate one of the largest fleets of land-based +drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, +Utah, Wyoming, Montana, North Dakota, Pennsylvania, West +Virginia and western Canada. +As of December 31, 2010, we had a drilling fleet that +consisted of 356 marketable land-based drilling rigs. A drilling +rig includes the structure, power source and machinery necessary +to cause a drill bit to penetrate the earth to a depth desired +by the customer. A drilling rig is considered marketable at a +point in time if it is operating or can be made ready to operate +without significant capital expenditures. We also have a +substantial inventory of drill pipe and drilling rig components. +We provide pressure pumping services to oil and natural gas +operators primarily in Texas and the Appalachian Basin. Pressure +pumping services consist primarily of well stimulation and +cementing for completion of new wells and remedial work on +existing wells. We also own and invest in oil and natural gas +assets as a working interest owner. Our oil and natural gas +working interests are located primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas +operators offshore in the Gulf of Mexico and on land in Texas, +New Mexico, Oklahoma and Louisiana. We sold our drilling and +completion fluids services business on January 20, 2010. +On October 1, 2010 we acquired the assets and operations of +a pressure pumping business and an electric wireline business. +The electric wireline business that we acquired was classified +as held for sale at December 31, 2010 and sold on +January 27, 2011. The results of our drilling and +completion fluids services business and our electric wireline +business are presented as discontinued operations in this Report. +Industry +Segments +Our revenues, operating profits and identifiable assets are +primarily attributable to three industry segments: +• +contract drilling services, +• +pressure pumping services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2010 and +2008. In 2009, our pressure pumping services and oil and natural +gas exploration and production segments had operating profits +and our contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of +Notes to Consolidated Financial Statements included as a part of +Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract +Drilling Operations +General — We market our contract drilling +services to major and independent oil and natural gas operators. +As of December 31, 2010, we had 356 marketable land-based +drilling rigs based in the following regions: +• +73 in west Texas and southeastern New Mexico, +• +97 in north central and east Texas, northern Louisiana and +Mississippi, +• +58 in the Rocky Mountain region (Colorado, Utah, Wyoming, +Montana and North Dakota), +• +51 in south Texas and southern Louisiana, +• +32 in the Texas panhandle, Oklahoma and Arkansas, +• +25 in the Appalachian Basin, and +• +20 in western Canada. +2 +Our marketable drilling rigs have rated maximum depth +capabilities ranging from 5,000 feet to 25,000 feet. +Of these drilling rigs, 124 are electric rigs and 232 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. We also have a substantial inventory of drill pipe and +drilling rig components, which may be used in the activation of +additional drilling rigs or as replacement parts for marketable +rigs. +Drilling rigs are typically equipped with engines, drawworks, +masts, pumps to circulate the drilling fluid, blowout +preventers, drill pipe and other related equipment. Over time, +components on a drilling rig are replaced or rebuilt. We spend +significant funds each year as part of a program to modify, +upgrade and maintain our drilling rigs to ensure that our +drilling equipment is competitive. We have spent +$1.4 billion during the last three years on capital +expenditures to (1) build new land drilling rigs, and +(2) modify, upgrade and maintain our drilling fleet. During +fiscal years 2010, 2009 and 2008, we spent approximately +$656 million, $395 million and $361 million, +respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are +the principal factors in determining the specifications of the +rig selected for a particular job. +Our contract drilling operations depend on the availability of +drill pipe, drill bits, replacement parts and other related rig +equipment, fuel and qualified personnel. Some of these have been +in short supply from time to time. +Drilling Contracts — Most of our drilling +contracts are with established customers on a competitive bid or +negotiated basis. Our drilling contracts are either on a +well-to-well +basis or a term basis. +Well-to-well +contracts are generally short-term in nature and cover the +drilling of a single well or a series of wells. Term contracts +are entered into for a specified period of time (frequently one +to three years) and provide for the use of the drilling rig to +drill multiple wells. During 2010, our average number of days to +drill a well (which includes moving to the drill site, rigging +up and rigging down) was approximately 21 days. +Our 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. +Most drilling contracts are subject to termination by the +customer on short notice and may or may not contain provisions +for the payment of an early termination fee to us in the event +that the contract is terminated by the customer. Generally, we +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. +Generally, the customers indemnify us against claims that might +arise from other surface and subsurface pollution. Each drilling +contract contains the actual terms setting forth our rights and +obligations and those of the customer, any of which rights and +obligations may deviate from what is customary due to industry +conditions or other factors. +Our drilling 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 job 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. +Under daywork contracts, we provide the drilling rig and crew to +the customer. The customer supervises the drilling of the well. +Our compensation is based on a contracted rate per day during +the period the drilling rig is utilized. We often receive a +lower rate when the drilling rig is moving or when drilling +operations are interrupted or restricted by adverse weather +conditions or other conditions beyond our control. Daywork +contracts typically provide separately for mobilization of the +drilling rig. Except for two wells drilled under footage +contracts in 2009, all of the wells we drilled in 2010, 2009 and +2008 were under daywork contracts. +Under footage contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed price per +foot. The customer provides drilling fluids, casing, cementing +and well design expertise. These contracts require us to bear +the cost of services and supplies that we provide until the well +has been drilled to the +agreed-upon +depth. If we drill the well in less time than estimated, we have +the opportunity to improve our profits over those that would be +attainable under a daywork contract. Profits are reduced and +losses may be incurred if the well requires more days to drill +to the contracted depth than estimated. Footage contracts +generally contain greater risks for a drilling contractor than +daywork contracts. Under footage contracts, the drilling +contractor typically assumes +3 +certain risks associated with loss of the well from fire, +blowouts and other risks. We drilled two wells under footage +contracts in 2009, and we did not drill any wells under footage +contracts in 2010 or 2008. +Under turnkey contracts, we contract to drill a well to a +certain depth under specified conditions for a fixed fee. In a +turnkey arrangement, we are required to bear the costs of +services, supplies and equipment beyond those typically provided +under a footage contract. In addition to the drilling rig and +crew, we are required to provide the drilling and completion +fluids, casing, cementing, and the technical well design and +engineering services during the drilling process. We also +typically assume certain risks associated with drilling the well +such as fires, blowouts, cratering of the well bore and other +such risks. Compensation occurs only when the agreed- upon scope +of the work has been completed, which requires us to make larger +up-front working capital commitments prior to receiving payments +under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling +process goes as expected and there are no complications or time +delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during +the drilling process. Turnkey contracts generally involve the +highest degree of risk among the three different types of +drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey +contracts in the past three years. +Contract Drilling Activity — Information +regarding our contract drilling activity for the last three +years follows: +Year Ended December 31, +2010 +2009 +2008 +Average rigs operating per day(1) +168 +91 +254 +Number of rigs operated during the year +220 +243 +315 +Number of wells drilled during the year +2,919 +1,539 +4,218 +Number of operating days(2) +61,244 +33,394 +93,068 +(1) +A rig is considered to be operating if it is earning revenue +pursuant to a contract on a given day. +(2) +Includes standby days under term contracts where revenue was +earned but the rig was not working. The number of these standby +days under term contracts was zero in 2010, 2,070 in 2009 and +486 in 2008. +Drilling Rigs and Related Equipment — We +estimate the depth capacity with respect to our marketable rigs +as of December 31, 2010 to be as follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,000 to 7,999 +— +3 +3 +8,000 to 11,999 +59 +9 +68 +12,000 to 15,999 +193 +8 +201 +16,000 to 25,000 +84 +— +84 +Totals +336 +20 +356 +At December 31, 2010, we owned and operated 317 trucks and +402 trailers used to rig down, transport and rig up our drilling +rigs. Our ownership of trucks and trailers reduces our +dependency upon third parties for these services and generally +enhances the efficiency of our contract drilling operations, +particularly in periods of high drilling rig utilization. +Most repair and overhaul work to our drilling rig equipment is +performed at our yard facilities located in Texas, Oklahoma, +Wyoming, Utah, Pennsylvania and western Canada. +Pressure +Pumping Operations +General — We provide pressure pumping services +to oil and natural gas operators primarily in Texas and the +Appalachian Basin. Pressure pumping services consist of well +stimulation and cementing for the completion of new wells and +remedial work on existing wells. Wells drilled in shale +formations and other unconventional plays require +4 +well stimulation through fracturing to allow the flow of oil and +natural gas. This is accomplished by pumping fluids under +pressure into the well bore to fracture the formation. Many +wells in conventional plays also receive well stimulation +services. The cementing process inserts material between the +wall of the well bore and the casing to support and stabilize +the casing. +Equipment — Our pressure pumping equipment at +December 31, 2010 includes equipment used in providing +hydraulic and nitrogen fracturing services as well as nitrogen, +cementing and acid pumping services as follows: +Quintiplex +Triplex +Other +Fracturing +Fracturing +Pumping +Equipment +Equipment +Equipment +Total +Number of Units +101 +90 +130 +321 +Approximate Hydraulic Horsepower +226,750 +126,850 +81,600 +435,200 +Our pressure pumping operations are supported by a fleet of +equipment including blenders, tractors, manifold trailers and +numerous trailers for transportation of materials to and from +the worksite as well as bins for storage of materials at the +worksite. +Oil and +Natural Gas Interests +We own and invest in oil and natural gas assets as a working +interest owner. Our oil and natural gas working interests are +located primarily in producing regions of Texas and New Mexico. +Customers +The customers of each of our contract drilling and pressure +pumping business segments are oil and natural gas operators. Our +customer base includes both major and independent oil and +natural gas operators. During 2010, no single customer accounted +for 10% or more of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly +competitive. Historically, available equipment used in these +businesses has frequently exceeded demand in our markets. The +price for our services is a key competitive factor in our +markets, in part because equipment used in our businesses can be +moved from one area to another in response to market conditions. +In addition to price, we believe availability and condition of +equipment, quality of personnel, service quality and safety +record are key factors in determining which contractor is +awarded a job in the markets in which we operate. We expect that +the market for land drilling and pressure pumping services will +continue to be highly competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, +other waste materials and acids, +• +use of underground storage tanks, +• +use of underground injection wells, and +• +hydraulic fracturing and related activities. +To date, applicable environmental laws and regulations in the +United States and Canada have not required the expenditure of +significant resources outside the ordinary course of business. +We do not anticipate any material capital expenditures for +environmental control facilities or extraordinary expenditures +to comply with +5 +environmental rules and regulations in the foreseeable future. +However, compliance costs under existing laws or under any new +requirements could become material, and we could incur liability +in any instance of noncompliance. +Our business is generally affected by political developments and +by Federal, state, foreign, and local laws and regulations that +relate to the oil and natural gas industry. The adoption of laws +and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase +costs relating to drilling and production, and otherwise have an +adverse effect on our operations. Federal, state, foreign and +local environmental laws and regulations currently apply to our +operations and may become more stringent in the future. Any +suspension or moratorium of the services we provide, whether or +not short-term in nature, by a Federal, state, foreign or local +governmental authority, could have a material adverse effect on +our business, financial condition and results of operation. +We believe 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 operated by us or our +predecessors, which may have resulted, or may result, in soil +and groundwater contamination in certain locations. Any +contamination found on, under or originating from the properties +may be subject to remediation requirements under Federal, state, +foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or +operators. In addition, it is possible we could be held +responsible for oil and natural gas properties in which we own +an interest but are not the operator. +Some of the environmental laws and regulations that are +applicable to our business operations are discussed in the +following paragraphs, but the discussion does not cover all +environmental laws and regulations that govern our operations. +In the United States, the Federal Comprehensive Environmental +Response Compensation and Liability Act of 1980, as amended, +commonly known as CERCLA, and comparable state statutes impose +strict liability on: +• +owners and operators of sites, and +• +persons who disposed of or arranged for the disposal of +“hazardous substances” found at sites. +The Federal Resource Conservation and Recovery Act +(“RCRA”), as amended, and comparable state statutes +govern the disposal of “hazardous wastes.” Although +CERCLA currently excludes petroleum from the definition of +“hazardous substances,” and RCRA also excludes certain +classes of exploration and production wastes from regulation, +such exemptions by Congress under both CERCLA and RCRA may be +deleted, limited, or modified in the future. If such changes are +made to CERCLA +and/or RCRA, +we could be required to remove and remediate previously disposed +of materials (including materials disposed of or released by +prior owners or operators) from properties (including ground +water contaminated with hydrocarbons) and to perform removal or +remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution +Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water +spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may +subject a responsible party, such as us, to civil or criminal +actions. Although the liability for owners and operators is the +same +6 +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 activities include the performance of hydraulic fracturing +services to enhance the production of oil and natural gas from +formations with low permeability, such as shales. Due to +concerns raised relating to potential impacts of hydraulic +fracturing on groundwater quality, legislative and regulatory +efforts at the Federal level and in some states have been +initiated to render permitting and compliance requirements more +stringent for hydraulic fracturing or prohibit the activity +altogether. Such efforts could have an adverse effect on oil and +natural gas production activities, which in turn could have an +adverse effect on the hydraulic fracturing services that we +render for our exploration and production customers. +In Canada, a variety of Canadian federal, provincial and +municipal laws and regulations impose, among other things, +restrictions, liabilities and obligations in connection with the +generation, handling, use, storage, transportation, treatment +and disposal of hazardous substances and wastes and in +connection with spills, releases and emissions of various +substances to the environment. These laws and regulations also +require that facility sites and other properties associated with +our operations be operated, maintained, abandoned and reclaimed +to the satisfaction of applicable regulatory authorities. In +addition, new projects or changes to existing projects may +require the submission and approval of environmental assessments +or permit applications. These laws and regulations are subject +to frequent change, and the clear trend is to place increasingly +stringent limitations on activities that may affect the +environment. +Our operations are also subject to Federal, state, foreign and +local laws, rules and regulations for the control of air +emissions, including the Federal Clean Air Act and the Canadian +Environmental Protection Act. We are aware of the increasing +focus of local, state, national and international regulatory +bodies on greenhouse gas (GHG) emissions and climate change +issues. We are also aware of legislation proposed by United +States lawmakers and the Canadian legislature to reduce GHG +emissions, as well as GHG emissions regulations enacted by the +U.S. Environmental Protection Agency and the Canadian +provinces of Alberta and British Columbia. We will continue to +monitor and assess any new policies, legislation or regulations +in the areas where we operate to determine the impact of GHG +emissions and climate change on our operations and take +appropriate actions, where necessary. Any direct and indirect +costs of meeting these requirements may adversely affect our +business, results of operations and financial condition. +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, +• +fires, and +• +explosions. +These and other 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, including through: +• +oil or produced water spillage, +• +natural gas leaks, and +• +fires. +7 +We maintain insurance coverage of types and amounts that we +believe to be customary in the industry, but we are not fully +insured against all risks, either because insurance is not +available or because of the high premium costs. Such risks +include personal injury, well disasters, extensive fire damage, +damage to the environment, and other hazards. The insurance +coverage that we maintain includes insurance for fire, windstorm +and other risks of physical loss to our rigs and other assets, +employer’s liability, automobile liability, commercial +general liability insurance, and workers compensation insurance. +We cannot assure, however, that any insurance obtained by us +will be adequate to cover any losses or liabilities, or that +this insurance will continue to be available or available on +terms that are acceptable to us. While we carry insurance to +cover physical damage to, or loss of, our drilling rigs and +other assets, such insurance does not cover the full replacement +cost of the rigs or other assets, and we do not carry insurance +against loss of earnings resulting from such damage. Liabilities +for which we are not insured, or which exceed the policy limits +of our applicable insurance, could have a material adverse +effect on our financial condition and results of operations. +In addition to insurance coverage, we also attempt to obtain +indemnification from our customers for certain risks. These +indemnity agreements typically require our customers to hold us +harmless in the event of loss of production or reservoir damage. +There is no assurance that we will obtain such contractual +indemnity, and if obtained, whether such indemnity will be +enforceable, whether the customer will be able to satisfy such +indemnity or whether such indemnity will be supported by +adequate insurance maintained by the customer. +Employees +We had approximately 7,000 full-time employees at +December 31, 2010. The number of employees fluctuates +depending on the current and expected demand for our services. +We consider our employee relations to be satisfactory. None of +our employees are represented by a union. +Seasonality +Seasonality does not significantly affect our overall +operations. However, our drilling operations in Canada and, to a +lesser extent, our pressure pumping operations in the +Appalachian Basin, are subject to slow periods of activity +during the annual Spring thaw. +Raw +Materials and Subcontractors +We use many suppliers of raw materials and services. Although, +these materials and services have historically been available, +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. \ No newline at end of file diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/item13.txt b/raw/filings/0000889900/2010/0000950123-11-013816/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..97cbc88da95dc5aeea63960da2883c0ca43e0a25 --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/item13.txt @@ -0,0 +1,6 @@ +Item 13. +Certain +Relationships and Related Transactions, and Director +Independence. +The information required by this Item is incorporated herein by +reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/item9a.txt b/raw/filings/0000889900/2010/0000950123-11-013816/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..493fd336d35da696a3739adeeef9c14aeaa70eb9 --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/item9a.txt @@ -0,0 +1,4362 @@ +Item 9A. Our responsibility is to express opinions on these +financial statements, on the financial statement schedule, and +on the Company’s internal control over financial reporting +based on our integrated audits. We conducted our audits in +accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we +plan and perform the audits to obtain reasonable assurance about +whether the financial statements are free of material +misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test +basis, evidence supporting the amounts and disclosures in the +financial statements, assessing the accounting principles used +and significant estimates made by management, and evaluating the +overall financial statement presentation. Our audit of internal +control over financial reporting included obtaining an +understanding of internal control over financial reporting, +assessing the risk that a material weakness exists, and testing +and evaluating the design and operating effectiveness of +internal control based on the assessed risk. Our audits also +included performing such other procedures as we considered +necessary in the circumstances. We believe that our audits +provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the +reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s +internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the +company; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of +management and directors of the company; and (iii) provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the +financial statements. +Because of its inherent limitations, internal control over +financial reporting may not prevent or detect misstatements. +Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become +inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +As described in Management’s Report on Internal Control +Over Financial Reporting, management has excluded Universal +Pressure Pumping, Inc. and Universal Wireline, Inc. from its +assessment of internal control over financial reporting as of +December 31, 2010 because they were formed in 2010 to +acquire certain pressure pumping and wireline businesses in a +business combination during the fourth quarter of 2010. We have +also excluded Universal Pressure Pumping, Inc. and Universal +Wireline, Inc. from our audit of internal control over financial +reporting. As of December 31, 2010, Universal Pressure +Pumping, Inc. and Universal Wireline, Inc. were wholly-owned +subsidiaries whose total assets and total revenues represented +9 percent and 6 percent, respectively, of the related +consolidated financial statement amounts as of and for the year +ended December 31, 2010. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 14, 2011 +F-2 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2010 +2009 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +27,612 +$ +49,877 +Accounts receivable, net of allowance for doubtful accounts of +$5,114 and $10,911 at December 31, 2010 and 2009, +respectively +337,167 +164,498 +Federal and state income taxes receivable +75,062 +118,869 +Inventory +17,215 +6,941 +Deferred tax assets, net +26,815 +32,877 +Assets held for sale +23,370 +42,424 +Other +50,169 +40,475 +Total current assets +557,410 +455,961 +Property and equipment, net +2,620,900 +2,110,402 +Goodwill and intangible assets +179,683 +86,234 +Deposits on equipment purchases +51,084 +914 +Other +13,954 +8,641 +Total assets +$ +3,423,031 +$ +2,662,152 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +162,400 +$ +83,700 +Accrued expenses +147,315 +108,750 +Current portion of long term debt +6,250 +— +Total current liabilities +315,965 +192,450 +Long term debt +392,500 +— +Deferred tax liabilities, net +511,422 +381,656 +Other +15,537 +6,346 +Total liabilities +1,235,424 +580,452 +Commitments and contingencies (see Note 9) +— +— +Stockholders’ equity: +Preferred stock, par value $.01; authorized +1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares +with 181,537,568 and 180,828,773 issued and 154,193,754 and +153,610,785 outstanding at December 31, 2010 and 2009, +respectively +1,815 +1,808 +Additional paid-in capital +796,641 +781,635 +Retained earnings +1,987,999 +1,901,853 +Accumulated other comprehensive income +21,597 +14,996 +Treasury stock, at cost, 27,343,814 shares and +27,217,988 shares at December 31, 2010 and 2009, +respectively +(620,445 +) +(618,592 +) +Total stockholders’ equity +2,187,607 +2,081,700 +Total liabilities and stockholders’ equity +$ +3,423,031 +$ +2,662,152 +The accompanying notes are an integral part of these +consolidated financial statements. +F-3 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +Year Ended December 31, +2010 +2009 +2008 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,081,898 +$ +599,287 +$ +1,804,026 +Pressure pumping +350,608 +161,441 +217,494 +Oil and natural gas +30,425 +21,218 +42,360 +Total operating revenues +1,462,931 +781,946 +2,063,880 +Operating costs and expenses: +Contract drilling +655,678 +357,742 +1,038,327 +Pressure pumping +235,100 +124,100 +147,377 +Oil and natural gas +7,020 +7,341 +12,793 +Depreciation, depletion, amortization and impairment +333,493 +289,847 +275,990 +Selling, general and administrative +53,042 +43,935 +43,273 +Net (gain) loss on asset disposals +(22,812 +) +3,385 +(4,163 +) +Provision for bad debts +(2,000 +) +3,810 +4,350 +Acquisition-related expenses +2,485 +— +— +Total operating costs and expenses +1,262,006 +830,160 +1,517,947 +Operating income (loss) +200,925 +(48,214 +) +545,933 +Other income (expense): +Interest income +1,674 +381 +1,553 +Interest expense +(12,772 +) +(4,148 +) +(630 +) +Other +927 +426 +502 +Total other income (expense) +(10,171 +) +(3,341 +) +1,425 +Income (loss) from continuing operations before income taxes +190,754 +(51,555 +) +547,358 +Income tax expense (benefit): +Current +(74,634 +) +(119,038 +) +128,098 +Deferred +147,490 +101,443 +65,392 +Total income tax expense (benefit) +72,856 +(17,595 +) +193,490 +Income (loss) from continuing operations +117,898 +(33,960 +) +353,868 +Loss from discontinued operations, net of income taxes +(956 +) +(4,330 +) +(6,799 +) +Net income (loss) +$ +116,942 +$ +(38,290 +) +$ +347,069 +Basic income (loss) per common share: +Income (loss) from continuing operations +$ +0.77 +$ +(0.22 +) +$ +2.29 +Loss from discontinued operations, net of income taxes +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Net income (loss) +$ +0.76 +$ +(0.25 +) +$ +2.25 +Diluted income (loss) per common share: +Income (loss) from continuing operations +$ +0.76 +$ +(0.22 +) +$ +2.27 +Loss from discontinued operations, net of income taxes +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Net income (loss) +$ +0.76 +$ +(0.25 +) +$ +2.23 +Weighted average number of common shares outstanding: +Basic +152,772 +152,069 +153,379 +Diluted +153,276 +152,069 +154,358 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.60 +The accompanying notes are an integral part of these +consolidated financial statements. +F-4 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Accumulated +Common Stock +Additional +Other +Number of +Paid-in +Retained +Comprehensive +Treasury +Shares +Amount +Capital +Earnings +Income +Stock +Total +(In thousands) +Balance, December 31, 2007 +177,386 +$ +1,773 +$ +703,581 +$ +1,716,620 +$ +20,207 +$ +(546,151 +) +$ +1,896,030 +Comprehensive income: +Net income +— +— +— +347,069 +— +— +347,069 +Foreign currency translation adjustment, (net of tax of $8,368) +— +— +— +— +(14,433 +) +— +(14,433 +) +Total comprehensive income +— +— +— +347,069 +(14,433 +) +— +332,636 +Issuance of restricted stock +577 +6 +(6 +) +— +— +— +— +Forfeitures of restricted stock +(75 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +2,304 +23 +25,525 +— +— +— +25,548 +Stock-based compensation +— +— +20,131 +— +— +— +20,131 +Tax benefit related to stock-based compensation +— +— +16,280 +— +— +— +16,280 +Payment of cash dividends +— +— +— +(92,865 +) +— +— +(92,865 +) +Purchase of treasury stock +— +— +— +— +— +(70,818 +) +(70,818 +) +Balance, December 31, 2008 +180,192 +1,801 +765,512 +1,970,824 +5,774 +(616,969 +) +2,126,942 +Comprehensive income (loss): +Net loss +— +— +— +(38,290 +) +— +— +(38,290 +) +Foreign currency translation adjustment, (net of tax of $5,347) +— +— +— +— +9,222 +— +9,222 +Total comprehensive loss +— +— +— +(38,290 +) +9,222 +— +(29,068 +) +Issuance of restricted stock +604 +6 +(6 +) +— +— +— +— +Vesting of restricted stock units +6 +— +— +— +— +— +— +Forfeitures of restricted stock +(56 +) +— +— +— +— +— +— +Exercise of stock options +83 +1 +568 +— +— +— +569 +Stock-based compensation +— +— +18,565 +— +— +— +18,565 +Tax expense related to stock-based compensation +— +— +(3,004 +) +— +— +— +(3,004 +) +Payment of cash dividends +— +— +— +(30,681 +) +— +— +(30,681 +) +Purchase of treasury stock +— +— +— +— +— +(1,623 +) +(1,623 +) +Balance, December 31, 2009 +180,829 +1,808 +781,635 +1,901,853 +14,996 +(618,592 +) +2,081,700 +Comprehensive income: +Net income +— +— +— +116,942 +— +— +116,942 +Foreign currency translation adjustment, (net of tax of $2,814) +— +— +— +— +6,601 +— +6,601 +Total comprehensive income +— +— +— +116,942 +6,601 +— +123,543 +Issuance of restricted stock +700 +7 +(7 +) +— +— +— +— +Vesting of restricted stock units +7 +— +— +— +— +— +— +Forfeitures of restricted stock +(59 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +61 +1 +524 +— +— +— +525 +Stock-based compensation +— +— +16,779 +— +— +— +16,779 +Tax expense related to stock-based compensation +— +— +(2,291 +) +— +— +— +(2,291 +) +Payment of cash dividends +— +— +— +(30,796 +) +— +— +(30,796 +) +Purchase of treasury stock +— +— +— +— +— +(1,853 +) +(1,853 +) +Balance, December 31, 2010 +181,538 +$ +1,815 +$ +796,641 +$ +1,987,999 +$ +21,597 +$ +(620,445 +) +$ +2,187,607 +The accompanying notes are an integral part of these +consolidated financial statements. +F-5 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Year Ended December 31, +2010 +2009 +2008 +(In thousands) +Cash flows from operating activities: +Net income (loss) +$ +116,942 +$ +(38,290 +) +$ +347,069 +Adjustments to reconcile net income (loss) to net cash provided +by operating activities: +Depreciation, depletion, amortization and impairment +333,493 +289,847 +275,990 +Provision for bad debts +(2,000 +) +3,810 +4,350 +Dry holes and abandonments +519 +129 +1,617 +Deferred income tax expense +147,490 +101,443 +65,392 +Stock-based compensation expense +16,779 +18,214 +19,688 +Net (gain) loss on asset disposals +(22,812 +) +3,385 +(4,163 +) +Tax expense related to stock-based compensation +(2,291 +) +(3,004 +) +— +Changes in operating assets and liabilities: +Accounts receivable +(178,444 +) +213,813 +(30,777 +) +Income taxes receivable/payable +43,522 +(108,664 +) +(11,258 +) +Inventory and other assets +(8,772 +) +14,178 +2,498 +Accounts payable +49,576 +(52,673 +) +6,486 +Accrued expenses +18,072 +(21,178 +) +(4,474 +) +Other liabilities +3,234 +(92 +) +1,242 +Net cash provided by operating activities of discontinued +operations +10,390 +32,759 +1,344 +Net cash provided by operating activities +525,698 +453,677 +675,004 +Cash flows from investing activities: +Acquisitions +(238,022 +) +— +— +Purchases of property and equipment +(738,090 +) +(452,646 +) +(445,426 +) +Proceeds from disposal of assets +29,409 +3,359 +11,436 +Net cash provided by (used in) investing activities of +discontinued operations +42,638 +(54 +) +(3,286 +) +Net cash used in investing activities +(904,065 +) +(449,341 +) +(437,276 +) +Cash flows from financing activities: +Purchases of treasury stock +(1,853 +) +(1,623 +) +(70,818 +) +Dividends paid +(30,796 +) +(30,681 +) +(92,865 +) +Tax benefit related to stock-based compensation +— +— +16,280 +Proceeds from long term debt +400,000 +— +— +Repayment of long term debt +(1,250 +) +— +— +Proceeds from borrowings under revolving credit facility +200,000 +— +— +Repayment of borrowings under revolving credit facility +(200,000 +) +— +(50,000 +) +Debt issuance costs +(10,779 +) +(6,169 +) +— +Proceeds from exercise of stock options +525 +569 +25,548 +Net cash provided by (used in) financing activities +355,847 +(37,904 +) +(171,855 +) +Effect of foreign exchange rate changes on cash +255 +2,222 +(2,084 +) +Net increase (decrease) in cash and cash equivalents +(22,265 +) +(31,346 +) +63,789 +Cash and cash equivalents at beginning of year +49,877 +81,223 +17,434 +Cash and cash equivalents at end of year +$ +27,612 +$ +49,877 +$ +81,223 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest expense, net of capitalized interest of $2,288 in 2010, +$0 in 2009 and $0 in 2008 +$ +— +$ +(1,804 +) +$ +(323 +) +Income taxes +115,666 +14,029 +(126,331 +) +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property +and equipment +$ +29,188 +$ +(25,110 +) +$ +(3,590 +) +Net (increase) decrease in deposits on equipment purchases +(50,170 +) +43,029 +(42,293 +) +The accompanying notes are an integral part of these +consolidated financial statements. +F-6 +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. +Description +of Business and Summary of Significant Accounting +Policies +A +description of the business and basis of presentation +follows: +Description of business — Patterson-UTI Energy, +Inc., through its wholly-owned subsidiaries (collectively +referred to herein as “Patterson-UTI” or the +“Company”), provides onshore contract drilling +services to major and independent oil and natural gas operators +primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, +Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, +Pennsylvania, West Virginia and western Canada. The Company +provides pressure pumping services primarily in Texas and the +Appalachian Basin. The Company also owns and invests in oil and +natural gas assets as a working interest owner primarily in +Texas and New Mexico. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and +its wholly-owned subsidiaries. All significant intercompany +accounts and transactions have been eliminated. Except for +wholly-owned subsidiaries, the Company has no controlling +financial interests in any other entity which would require +consolidation. +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 its functional currency. The +effects of exchange rate changes are reflected in accumulated +other comprehensive income, which is a separate component of +stockholders’ equity. +A +summary of the significant accounting policies +follows: +Management estimates — The preparation of +financial statements in conformity with accounting principles +generally accepted in the United States of America requires +management to make estimates and assumptions that affect the +reported amounts of assets and liabilities and disclosure of +contingent assets and liabilities at the date of the financial +statements and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from +such estimates. +Revenue recognition — Revenues are recognized +when services are performed, except for revenues earned under +turnkey contract drilling arrangements which are recognized +using the completed-contract method of accounting. The Company +follows the +percentage-of-completion +method of accounting for footage contract drilling arrangements. +Under the +percentage-of-completion +method, management estimates are relied upon in the +determination of the total estimated expenses to be incurred +drilling the well. Due to the nature of turnkey contract +drilling arrangements and the 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 as revenue reimbursements +received from third parties for +out-of-pocket +expenses and accounts for those +out-of-pocket +expenses as direct costs. Except for two wells drilled under +footage contracts in 2009, all of the wells the Company drilled +during the years ended December 31, 2010, 2009 and 2008 +were under daywork contracts. +Accounts receivable — Trade accounts receivable +are recorded at the invoiced amount. 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 at least quarterly. Significant individual +accounts receivable balances and balances which have been +outstanding greater than 90 days are reviewed individually +for collectibility. Account balances, when determined to be +uncollectible, are charged against the allowance. +Inventories — Inventories consist primarily of +sand and chemical products to be used in conjunction with the +Company’s pressure pumping activities. The inventories are +stated at the lower of cost or market, determined by the +first-in, +first-out method. +F-7 +Property and equipment — Property and equipment +is carried at cost less accumulated depreciation. Depreciation +is provided on the straight-line method over the estimated +useful lives. The method of depreciation does not change +whenever equipment becomes idle. The estimated useful lives, in +years, are shown below: +Useful Lives +Drilling rigs and other equipment +2-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are +evaluated for impairment when certain triggering events or +changes in circumstances indicate that the carrying values may +not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working +interests in oil and natural gas properties are accounted for +using the successful efforts method of accounting. Under the +successful efforts method of accounting, exploration costs which +result in the discovery of oil and natural gas reserves and all +development costs are capitalized to the appropriate well. +Exploration costs which do not result in discovering oil and +natural gas reserves are charged to expense when such +determination is made. 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 whether sufficient progress is being made +in assessing the reserves and economic viability of the +respective projects. If no progress has been made in assessing +the reserves and economic viability of a project after one year +following the completion of drilling, the Company considers the +well costs to be impaired and recognizes the costs as expense. +Geological and geophysical costs, including seismic costs, and +costs to carry and retain undeveloped properties are charged to +expense when incurred. The capitalized costs of both +developmental and successful exploratory type wells, consisting +of lease and well equipment, lease acquisition costs and +intangible development costs, are depreciated, depleted and +amortized on the +units-of-production +method, based on engineering estimates of proved oil and natural +gas reserves for each respective field. +The Company reviews its proved oil and natural gas properties +for impairment whenever a triggering event occurs, such as +downward revisions in reserve estimates or decreases in oil and +natural gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on +management’s expectation of future pricing over the lives +of the respective fields. These cash flow estimates are reviewed +by an independent petroleum engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment +expense is measured and recognized as the difference between net +book value and discounted cash flow. The discounted cash flow +estimates used in measuring impairment are based on +management’s expectations of future commodity prices over +the life of the respective field. The Company reviews unproved +oil and natural gas properties quarterly to assess potential +impairment. The Company’s impairment assessment is made on +a +lease-by-lease +basis and considers factors such as management’s intent to +drill, lease terms and abandonment of an area. If an unproved +property is determined to be impaired, the related property +costs are expensed. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. The +Company assesses impairment of its goodwill at least annually as +of December 31, or on an interim basis if events or +circumstances indicate that the fair value of goodwill may have +decreased below its carrying value. +Maintenance and repairs — Maintenance and +repairs are charged to expense when incurred. Renewals and +betterments which extend the life or improve existing property +and equipment are capitalized. +Disposals — Upon disposition of property and +equipment, the cost and related accumulated depreciation are +removed and any resulting gain or loss is reflected in the +consolidated statement of operations. +Net income (loss) per common share — The +Company provides a dual presentation of its net income (loss) +per common share in its consolidated statements of operations: +Basic net income (loss) per common share (“Basic EPS”) +and diluted net income (loss) per common share (“Diluted +EPS”). The Company adopted a new accounting standard on +January 1, 2009, which clarified that share-based payment +awards that entitle their holders to receive non-forfeitable +dividends before vesting should be considered participating +securities and, as such, should be included in the calculation +of +earnings-per-share +using the two-class method. All +earnings-per-share +data presented for the year ended December 31, 2008 have +been adjusted retrospectively to conform with this accounting +standard. +F-8 +The impact of this retrospective application to the year ended +December 31, 2008 was to reduce Basic EPS and Diluted EPS +by $0.01. +Basic EPS excludes dilution and is computed by first allocating +earnings between common stockholders and holders of non-vested +shares of restricted stock. Basic EPS is then determined by +dividing the earnings attributable to common stockholders by the +weighted average number of common shares outstanding during the +period, excluding non-vested shares of restricted stock. +Diluted EPS is based on the weighted average number of common +shares outstanding plus the dilutive effect of potential common +shares, including stock options, non-vested shares of restricted +stock and restricted stock units. The dilutive effect of stock +options and restricted stock units is determined using the +treasury stock method. The dilutive effect of non-vested shares +of restricted stock is based on the more dilutive of the +treasury stock method or the two-class method, assuming a +reallocation of undistributed earnings to common stockholders +after considering the dilutive effect of potential common shares +other than non-vested shares of restricted stock. +The following table presents information necessary to calculate +income (loss) from continuing operations per share, loss from +discontinued operations per share and net income (loss) per +share for the years ended December 31, 2010, 2009 and 2008, +as well as potentially dilutive securities excluded from the +weighted average number of diluted common shares outstanding +because their inclusion would have been anti-dilutive (in +thousands, except per share amounts): +2010 +2009 +2008 +BASIC EPS: +Income (loss) from continuing operations +$ +117,898 +$ +(33,960 +) +$ +353,868 +Adjust for (income) loss attributed to holders of non-vested +restricted stock +(884 +) +313 +(3,279 +) +Income (loss) from continuing operations attributed to common +stockholders +$ +117,014 +$ +(33,647 +) +$ +350,589 +Loss from discontinued operations, net +$ +(956 +) +$ +(4,330 +) +$ +(6,799 +) +Adjust for loss attributed to holders of non-vested restricted +stock +7 +38 +64 +Loss from discontinued operations attributed to common +stockholders +$ +(949 +) +$ +(4,292 +) +$ +(6,735 +) +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,772 +152,069 +153,379 +Basic income (loss) from continuing operations per common share +$ +0.77 +$ +(0.22 +) +$ +2.29 +Basic loss from discontinued operations per common share +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Basic net income (loss) per common share +$ +0.76 +$ +(0.25 +) +$ +2.25 +F-9 +2010 +2009 +2008 +DILUTED EPS: +Income (loss) from continuing operations attributed to common +stockholders +$ +117,014 +$ +(33,647 +) +$ +350,589 +Add incremental earnings related to potential common shares +— +— +15 +Adjusted income (loss) from continuing operations attributed to +common stockholders +$ +117,014 +$ +(33,647 +) +$ +350,604 +Weighted average number of common shares outstanding, excluding +non-vested shares of restricted stock +152,772 +152,069 +153,379 +Add dilutive effect of potential common shares +504 +— +979 +Weighted average number of diluted common shares outstanding +153,276 +152,069 +154,358 +Diluted income (loss) from continuing operations per common share +$ +0.76 +$ +(0.22 +) +$ +2.27 +Diluted loss from discontinued operations per common share +$ +(0.01 +) +$ +(0.03 +) +$ +(0.04 +) +Diluted net income (loss) per common share +$ +0.76 +$ +(0.25 +) +$ +2.23 +Potentially dilutive securities excluded as anti-dilutive +4,164 +8,090 +2,455 +Income taxes — The asset and liability method +is used in accounting for income taxes. Under this method, +deferred tax assets and liabilities are recognized for operating +loss and tax credit carryforwards and for the future tax +consequences attributable to differences between the financial +statement carrying amounts of existing assets and liabilities +and their respective tax bases. Deferred tax assets and +liabilities are measured using enacted tax rates expected to +apply to taxable income in the year in which those temporary +differences are expected to be recovered or settled. The effect +on deferred tax assets and liabilities of a change in tax rates +is recognized in the results of operations in the period that +includes the enactment date. If applicable, a valuation +allowance is recorded to reduce the carrying amounts of deferred +tax assets unless it is more likely than not that such assets +will be realized. The Company’s policy is to account for +interest and penalties with respect to income taxes as operating +expenses. +Stock-based compensation — The Company +recognizes the cost of share-based payments under the +fair-value-based method. Under this method, compensation cost +related to share-based payments is measured based on the +estimated fair value of the awards at the date of grant, net of +estimated forfeitures. This expense is recognized over the +expected life of the awards (See Note 11). +Statement of cash flows — For purposes of +reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Recently Issued Accounting Standards — In June +2009, the FASB issued a new accounting standard that amends the +accounting and disclosure requirements for the consolidation of +variable interest entities. This new standard removes the +previously existing exception from applying consolidation +guidance to qualifying special-purpose entities and requires +ongoing reassessments of whether an enterprise is the primary +beneficiary of a variable interest entity. Prior to this new +standard, generally accepted accounting principles required +reconsideration of whether an enterprise is the primary +beneficiary of a variable interest entity only when specific +events occurred. This new standard is effective as of the +beginning of each reporting entity’s first annual reporting +period that begins after November 15, 2009, for interim +periods within that first annual reporting period, and for +interim and annual reporting periods thereafter. This new +standard became effective for the Company on January 1, +2010. The adoption of this standard did not impact the +Company’s consolidated financial statements. +In October 2009, the FASB issued a new accounting standard that +addresses the accounting for multiple-deliverable revenue +arrangements to enable vendors to account for deliverables +separately rather than as a combined unit. This new standard +addresses how to separate deliverables and how to measure and +allocate arrangement consideration to one or more units of +accounting. Existing accounting standards require a vendor to +use objective +F-10 +and reliable evidence of fair value for the undelivered items or +the residual method to separate deliverables in a +multiple-deliverable arrangement. Under the new standard, it is +expected that multiple-deliverable arrangements will be +separated in more circumstances than under current requirements. +The new standard establishes a hierarchy for determining the +selling price of a deliverable for purposes of allocating +revenue to multiple deliverables. The selling price used will be +based on vendor-specific objective evidence if available, +third-party evidence if vendor-specific objective evidence is +not available, or estimated selling price if neither +vendor-specific objective evidence nor third-party evidence is +available. The new standard must be prospectively applied to all +revenue arrangements entered into in fiscal years beginning on +or after June 15, 2010 and became effective for the Company +on January 1, 2011. The adoption of this standard is not +expected to have a material impact on the Company’s +consolidated financial position, results of operations or cash +flows. +In December 2010, the FASB issued an accounting standard update +that addresses the disclosure of supplementary pro forma +information for business combinations. This update clarifies +that when public entities are required to disclose pro forma +information for business combinations that occurred in the +current reporting period, the pro forma information should be +presented as if the business combination occurred as of the +beginning of the previous fiscal year when comparative financial +statements are presented. This update is effective prospectively +for business combinations for which the acquisition date is on +or after the beginning of the first annual reporting period +beginning on or after December 15, 2010. Early adoption is +permitted. The Company elected to early adopt this update and +this early adoption did not have an impact on the Company’s +consolidated financial position, results of operations or cash +flows. +Reclassifications — Certain reclassifications +have been made to the 2009 and 2008 consolidated financial +statements in order for them to conform with the 2010 +presentation. These reclassifications had no significant impact +on the Company’s financial position, results of operations +or cash flows. +2. +Discontinued +Operations +On January 27, 2011, the stock of the Company’s +electric wireline subsidiary, Universal Wireline, Inc., was sold +in a cash transaction for $25.5 million. Except for +inventory, the working capital of Universal Wireline, Inc. was +excluded from the sale and retained by a subsidiary of the +Company. Universal Wireline, Inc. was formed in 2010 to acquire +the electric wireline business of Key Energy Services, Inc., as +discussed in Note 3. The results of operations of this +business have been presented as results of discontinued +operations in these consolidated financial statements. As of +December 31, 2010, the assets to be disposed of were +classified as held for sale and are presented separately within +current assets under the caption “Assets held for +sale” in the consolidated balance sheet. Upon being +classified as held for sale, the assets to be disposed of were +recorded at fair value less estimated costs to sell resulting in +a charge of $2.2 million. Due to the fact that the carrying +value of the assets had been adjusted to net realizable value, +no significant additional gain or loss was recognized in +connection with the sale. +On January 20, 2010, the Company exited the drilling and +completion fluids business, which had previously been presented +as one of the Company’s reportable operating segments. On +that date, the Company’s wholly owned subsidiary, Ambar +Lone Star Fluids Services LLC, completed the sale of +substantially all of its assets, excluding billed accounts +receivable. The sales price was approximately +$42.6 million. Upon the Company’s exit from the +drilling and completion fluids business, the Company classified +its drilling and completion fluids operating segment as a +discontinued operation. Accordingly, the results of operations +of this business have been reclassified and presented as results +of discontinued operations for all periods presented in these +consolidated financial statements. As of December 31, 2009, +the assets to be disposed of were considered held for sale and +were presented separately within current assets under the +caption “Assets held for sale” in the consolidated +balance sheet. Upon being classified as held for sale, the +assets to be disposed of were adjusted to fair value less +estimated costs to sell resulting in an impairment loss of +$1.9 million. Due to the fact that the carrying value of +the assets had been adjusted to net realizable value, no +significant additional gain or loss was recognized in connection +with the sale in 2010. +F-11 +Summarized operating results from discontinued operations for +the years ended December 31, 2010, 2009 and 2008 are shown +below (in thousands): +2010 +2009 +2008 +Drilling and completion fluids revenues +$ +3,737 +$ +79,786 +$ +145,246 +Electric wireline revenues +5,712 +— +— +Operating revenues from discontinued operations +$ +9,449 +$ +79,786 +$ +145,246 +Loss before income taxes +$ +(1,499 +) +$ +(6,538 +) +$ +(4,410 +) +Income tax benefit (expense) +543 +2,208 +(2,389 +) +Loss from discontinued operations +$ +(956 +) +$ +(4,330 +) +$ +(6,799 +) +The loss before income taxes in 2008 includes approximately +$10.0 million in non-deductible charges resulting from the +impairment of goodwill. As a result, income tax expense was +incurred for the year despite the fact that the discontinued +operation had a pre-tax book loss. +The components of assets held for sale at December 31, 2010 +and 2009 are shown below (in thousands): +2010 +2009 +Assets held for sale: +Inventory +$ +756 +$ +28,620 +Unbilled accounts receivable +— +6,587 +Prepaid expenses and other current assets +— +324 +Property and equipment, net +24,769 +8,793 +Reserve to reduce disposal group to fair value less costs to sell +(2,155 +) +(1,900 +) +Total assets held for sale +$ +23,370 +$ +42,424 +3. +Acquisitions +On October 1, 2010, two subsidiaries of the Company, +Universal Pressure Pumping, Inc. and Universal Wireline, Inc., +completed the acquisition of certain assets from Key Energy +Pressure Pumping Services, LLC and Key Electric Wireline +Services, LLC relating to the businesses of providing pressure +pumping services and electric wireline services to participants +in the oil and natural gas industry. This acquisition expanded +the Company’s pressure pumping operations to additional +markets primarily in Texas. The aggregate purchase price was +$241 million consisting of a cash payment of +$238 million at closing funded through a combination of +cash on hand and a $200 million draw on the Company’s +revolving credit facility, a subsequent cash payment based on +the value of closing inventory of approximately +$1.2 million to be made in the first quarter of 2011 and +the assumption of liabilities of approximately +$2.1 million. The purchase price was allocated to the +tangible and identifiable intangible assets acquired and +liabilities assumed based on fair value. The tangible assets +acquired include property and equipment, inventories of sand and +chemicals on hand and repair and maintenance supplies on hand. +The identifiable intangible assets acquired include an agreement +by the seller to not compete for a period of three years and the +customer relationships in place at the time of the acquisition. +The liabilities assumed arose from pricing agreements in place +with certain customers that had pricing below current market +rates. A related deferred tax asset was recognized to reflect +the temporary difference associated with these below-market +pricing arrangements. The excess of the purchase price over the +fair values of the tangible assets, the identifiable intangible +assets and deferred +F-12 +tax asset, net of the liabilities assumed is recorded as +goodwill and was attributed to the pressure pumping business +acquired. A summary of the purchase price allocation follows (in +thousands): +Sand and chemical inventory +$ +6,848 +Supplies +312 +Property and equipment +154,359 +Non-compete agreement +1,400 +Customer relationships +25,500 +Deferred tax asset +8,514 +Goodwill +67,575 +Below-market pricing agreements +(23,200 +) +Total purchase price +$ +241,308 +In addition to the purchase price, acquisition-related expenses +associated with this transaction of approximately +$2.5 million were incurred by the Company and are presented +in the consolidated statement of operations under the caption +“acquisition-related expenses” for the year ended +December 31, 2010. These expenses include certain legal and +other professional fees directly related to the transaction, +fees incurred in connection with title transfers of the acquired +equipment and transition costs related to information technology. +As discussed in Note 2, the electric wireline business was +classified as held for sale at December 31, 2010 and was +subsequently sold on January 27, 2011. The results of +operations of the wireline business from the date of acquisition +included revenue of $5.7 million and a pre-tax operating +loss of $1.5 million (including a charge of approximately +$2.2 million incurred to reduce the carrying value of the +disposal group to its net realizable value) which is included in +loss from discontinued operations for the year ended +December 31, 2010. Results of operations of the acquired +pressure pumping business are included in the Company’s +consolidated results of operations from the date of acquisition. +Revenues of $84.7 million and income from operations of +$22.8 million from the acquired pressure pumping business +are included in the consolidated statement of operations for the +year ended December 31, 2010. +The following represents pro-forma unaudited financial +information for the years ended December 31, 2010 and 2009 as if +the acquisition had been completed on January 1, 2009 (in +thousands, except per share amounts): +2010 +2009 +(Unaudited) +Revenue +$ +1,660,635 +$ +905,168 +Income (loss) from continuing operations +$ +127,257 +$ +(46,807 +) +Net income (loss) +$ +126,301 +$ +(51,137 +) +Basic income (loss) from continuing operations per common share +$ +0.83 +$ +(0.33 +) +Basic net income (loss) per common share +$ +0.83 +$ +(0.36 +) +Diluted income (loss) from continuing operations per common share +$ +0.82 +$ +(0.33 +) +Diluted net income (loss) per common share +$ +0.82 +$ +(0.36 +) +F-13 +4. +Property +and Equipment +Property and equipment consisted of the following at +December 31, 2010 and 2009 (in thousands): +2010 +2009 +Equipment +$ +3,972,891 +$ +3,230,737 +Oil and natural gas properties +110,749 +93,354 +Buildings +61,425 +56,563 +Land +11,074 +9,795 +4,156,139 +3,390,449 +Less accumulated depreciation and depletion +(1,535,239 +) +(1,280,047 +) +Property and equipment, net +$ +2,620,900 +$ +2,110,402 +Depreciation, depletion, amortization and +impairment — The following table summarizes +depreciation, depletion, amortization and impairment expense +related to property and equipment and intangible assets for +2010, 2009 and 2008 (in millions): +2010 +2009 +2008 +Depreciation and impairment expense +$ +322.3 +$ +280.6 +$ +264.5 +Amortization expense +1.0 +— +— +Depletion expense +10.2 +9.2 +11.5 +Total +$ +333.5 +$ +289.8 +$ +276.0 +The Company evaluates the recoverability of its long-lived +assets whenever events or changes in circumstances indicate that +their carrying amounts may not be recoverable. In light of +adverse market conditions affecting the Company beginning in the +fourth quarter of 2008 and continuing into 2009, including a +substantial decrease in the operating levels of certain of its +business segments and a significant decline in oil and natural +gas commodity prices, the Company deemed it necessary to assess +the recoverability of long-lived assets within its contract +drilling segment in 2008. Due to a continued decrease in the +operating levels within its contract drilling business segment +through the first three quarters of 2009, the Company again +deemed it necessary to perform an impairment assessment of +long-lived assets in its contract drilling segment in 2009. In +light of the recent favorable trends in rig utilization and +revenue per operating day experienced by the Company and its +peers, management concluded that no triggering event had +occurred in 2010 with respect to its contract drilling segment. +With respect to the long-lived assets in the Company’s oil +and natural gas exploration and production segment, the Company +assesses the recoverability of long-lived assets at the end of +each quarter due to revisions in its oil and natural gas reserve +estimates and expectations about future commodity prices. The +Company concluded that its pressure pumping segment was not +subject to the negative events and trends to the same degree as +the contract drilling segment, and thus did not require further +assessment of recoverability in 2010, 2009 or 2008. +The Company performs the first step of its impairment +assessments by comparing the undiscounted cash flows for each +long-lived asset or asset group to its respective carrying +value. Based on the results of these impairment tests, the +carrying amounts of long-lived assets in the contract drilling +and oil and natural gas segments were determined to be +recoverable, except as described below. +The Company’s analysis indicated that the carrying amounts +of certain oil and natural gas properties were not recoverable +at various testing dates in 2010, 2009 and 2008. The +Company’s estimates of expected future net cash flows from +impaired properties are used in measuring the fair value of such +properties. The Company recorded impairment charges of $792,000, +$3.7 million and $4.4 million in 2010, 2009 and 2008, +respectively, related to its oil and natural gas properties. The +Company determined the fair value of the impaired assets using +internally developed unobservable inputs including future +pricing and reserves (level 3 inputs in the fair value +hierarchy of fair value accounting). +During 2010, 2009 and 2008, in connection with its long-term +planning process, the Company evaluated its then-current fleet +of marketable drilling rigs and identified four, 23 and 22 rigs, +respectively, that it determined +F-14 +would no longer be marketed as rigs. The components comprising +these rigs were evaluated, and those components with continuing +utility to the Company’s other marketed rigs were +transferred to other rigs or yards to be used as spare +equipment. The remaining components of these rigs were impaired +and the associated net book value of $4.2 million in 2010, +$10.5 million in 2009 and $10.4 million in 2008 was +expensed in the Company’s consolidated statements of +operations as an impairment charge. The impaired components were +estimated to have no fair value. +During 2010, the Company sold certain rights to explore and +develop zones deeper than depths that it generally targets for +certain of the oil and natural gas properties in which it has +working interests. The proceeds from this sale were +approximately $22.3 million and the sale resulted in a gain +on disposal of $20.1 million. +5. +Goodwill +and Intangible Assets +Goodwill — Goodwill by operating segment as of +December 31, 2010 and 2009 and changes for the years then +ended are as follows (in thousands): +2010 +2009 +Contract Drilling: +Balance as of January 1: +Goodwill +$ +86,234 +$ +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Changes to goodwill +— +— +Balance as of December 31: +Goodwill +86,234 +86,234 +Accumulated impairment losses +— +— +86,234 +86,234 +Pressure Pumping: +Balance as of January 1: +Goodwill +— +— +Accumulated impairment losses +— +— +Goodwill recorded in connection with business combination +67,575 +— +Balance as of December 31: +Goodwill +67,575 +— +Accumulated impairment losses +— +— +67,575 +— +Total goodwill as of December 31 +$ +153,809 +$ +86,234 +Goodwill recorded in connection with a business combination in +2010 was a result of the Company’s acquisition of the +pressure pumping business of Key Energy Services, Inc. on +October 1, 2010, as discussed further in Note 3. +Approximately $53.2 million of this goodwill is expected to be +deductible for tax purposes. +Goodwill is evaluated at least annually on December 31 to +determine if the fair value of recorded goodwill has decreased +below its carrying value. For purposes of impairment testing, +goodwill is evaluated at the reporting unit level. The +Company’s reporting units for impairment testing have been +determined to be its operating segments. +The Company performed its annual goodwill impairment assessment +as of December 31, 2009 related to the $86.2 million +in goodwill recorded in its contract drilling reporting unit. In +completing its first step of the analysis, the Company used a +three-year projection of discounted cash flows, plus a terminal +value determined using the constant growth method to estimate +the fair value of the reporting unit. In developing this fair +value estimate, the Company applied key assumptions, including +an assumed discount rate of 15.42% and an assumed long-term +growth rate of 3.50%. Based +F-15 +on the results of the first step of the impairment test in 2009, +the Company concluded that no impairment was indicated in its +contract drilling reporting unit as the estimated fair value of +that reporting unit exceeded its carrying value. +The Company performed its annual goodwill impairment assessment +as of December 31, 2010. In completing its first step of +the analysis, the Company estimated its enterprise value based +on the market capitalization of the Company as determined by +reference to the closing price of the Company’s common +stock during the fifteen days before and after year end. The +enterprise value was allocated to the Company’s reporting +units and it was determined that the fair values of the +Company’s reporting units were in excess of their carrying +value. As a result, the Company concluded that no impairment of +goodwill was indicated as of December 31, 2010. +In the event that market conditions weaken, the Company may +determine additional impairments of goodwill in its contract +drilling or pressure pumping reporting units in the future, and +such impairment could be material. +Intangible Assets — Intangible assets were +recorded in the pressure pumping operating segment in connection +with the fourth quarter 2010 acquisition of the assets of the +pressure pumping business discussed in Note 3. As a result +of the purchase price allocation, the Company recorded +intangible assets related to a non-compete agreement and the +customer relationships acquired. These intangible assets were +recorded at fair value on the date of acquisition. +The non-compete agreement has a term of three years from +October 1, 2010. The value of this agreement was estimated +using a with and without scenario where cash flows were +projected through the term of the agreement assuming the +agreement is in place and compared to cash flows assuming the +non-compete agreement was not in place. The intangible asset +associated with the non-compete agreement is being amortized on +a straight-line basis over the three-year term of the agreement. +Amortization expense of $116,000 was recorded in the year ended +December 31, 2010 associated with the non-compete agreement. +The value of the customer relationships was estimated using a +multi-period excess earnings model to determine the present +value of the projected cash flows associated with the customers +in place at the time of the acquisition and taking into account +a contributory asset charge. The resulting intangible asset is +being amortized on a straight-line basis over seven years. +Amortization expense of $910,000 was recorded in the year ended +December 31, 2010 associated with customer relationships. +The following table sets forth the activity with respect to +intangible assets for the year ended December 31, 2010 (in +thousands): +Customer +Non-compete +Relationships +Total +Intangible assets at January 1, 2010 +$ +— +$ +— +$ +— +Intangible assets recognized at fair value in business +combination +1,400 +25,500 +26,900 +Amortization expense +(116 +) +(910 +) +(1,026 +) +Accumulated amortization at December 31, 2010 +(116 +) +(910 +) +(1,026 +) +Intangible assets, net at December 31, 2010 +$ +1,284 +$ +24,590 +$ +25,874 +F-16 +6. +Accrued +Expenses +Accrued expenses consisted of the following at December 31, +2010 and 2009 (in thousands): +2010 +2009 +Salaries, wages, payroll taxes and benefits +$ +39,766 +$ +15,657 +Workers’ compensation liability +63,011 +65,825 +Sales, use and other taxes +6,782 +11,090 +Insurance, other than workers’ compensation +12,648 +12,498 +Deferred revenue — current +10,220 +— +Other +14,888 +3,680 +$ +147,315 +$ +108,750 +Deferred revenue was recorded in 2010 in the purchase price +allocation associated with the Company’s acquisition of a +pressure pumping business as discussed in Note 3. The +deferred revenue relates to +out-of-market +pricing agreements that were in place at the acquired business +at the time of the acquisition. The deferred revenue will be +recognized as pressure pumping revenue over the remaining term +of the pricing agreements. Deferred revenue of approximately +$6.1 million was recognized in the year ended +December 31, 2010 related to these pricing agreements. +7. +Asset +Retirement Obligation +The Company records a liability for the estimated costs to be +incurred in connection with the abandonment of oil and natural +gas properties in the future. This liability is included in the +caption “other” in the liabilities section of the +consolidated balance sheet. The following table describes the +changes to the Company’s asset retirement obligations +during 2010 and 2009 (in thousands): +2010 +2009 +Balance at beginning of year +$ +2,955 +$ +3,047 +Liabilities incurred +335 +157 +Liabilities settled +(339 +) +(354 +) +Accretion expense +112 +118 +Revision in estimated costs of plugging oil and natural gas wells +— +(13 +) +Asset retirement obligation at end of year +$ +3,063 +$ +2,955 +8. +Long Term +Debt +In March 2009, the Company entered into an unsecured revolving +credit facility (the “2009 Credit Facility”) with a +maximum borrowing capacity of $240 million. The Company +incurred debt issuance costs of approximately $6.2 million +during 2009 in connection with the 2009 Credit Facility. These +costs were being amortized to interest expense over the +contractual term of the 2009 Credit Facility. +On July 2, 2010, the Company entered into a +364-Day +Credit Agreement (the +“364-Day +Credit Agreement”) among the Company, as borrower, and +Wells Fargo Bank, N.A., as administrative agent and lender. The +364-Day +Credit Agreement was a committed senior unsecured single draw +term loan credit facility that permitted a borrowing of up to +$250 million, provided that the loan must have been drawn +no later than September 30, 2010 or, if an additional fee +was paid, October 30, 2010. The maturity date under the +364-Day +Credit Agreement was 364 days after the date on which the +closing conditions under the +364-Day +Credit Agreement were met. This facility was not drawn as of +September 30, 2010 and it expired at that time. +On August 19, 2010, the Company entered into a Credit +Agreement (the “2010 Credit Agreement”) among the +Company, as borrower, Wells Fargo Bank, N.A., as administrative +agent, letter of credit issuer, swing line lender and lender, +and each of the other letter of credit issuer and lender parties +thereto. The 2010 Credit Agreement is a +F-17 +committed senior unsecured credit facility that includes a +revolving credit facility and a term loan facility. The 2010 +Credit Agreement replaced the 2009 Credit Facility. +The revolving credit facility permits aggregate borrowings of up +to $400 million and contains a letter of credit facility +that is limited to $150 million and a swing line facility +that is limited to $40 million. Subject to customary +conditions, the Company may request that the lenders’ +aggregate commitments with respect to the revolving credit +facility be increased by up to $100 million, not to exceed +total commitments of $500 million. The maturity date for +the revolving facility is August 19, 2013. +The term loan facility provided for a loan of $100 million +which was funded on August 19, 2010. The term loan facility +is payable in quarterly principal installments commencing +November 19, 2010, and the installment amounts vary from +1.25% of the original principal amount for each of the first +four quarterly installments, 2.50% of the original principal +amount for each of the subsequent eight quarterly installments, +5.00% of the original principal amount for the next subsequent +three quarterly installments and the remainder is due at +maturity. The maturity date for the term loan facility is +August 19, 2014. +Loans under the 2010 Credit Agreement bear interest by +reference, at the Company’s election, to the LIBOR rate or +base rate. The applicable margin on LIBOR rate loans varies from +2.75% to 3.75% and the applicable margin on base rate loans +varies from 1.75% to 2.75%, in each case determined based upon +the Company’s debt to capitalization ratio. As of +December 31, 2010, the applicable margin on LIBOR rate +loans was 2.75% and the applicable margin on base rate loans was +1.75%. A letter of credit fee is payable by the Company equal to +the applicable margin for LIBOR rate loans times the daily +amount available to be drawn under outstanding letters of +credit. The commitment fee payable to the lenders for the unused +portion of the revolving credit facility varies from 0.50% to +0.75% based upon the Company’s debt to capitalization ratio +and was 0.50% as of December 31, 2010. +Each domestic subsidiary of the Company other than any +immaterial subsidiary has unconditionally guaranteed all +existing and future indebtedness and liabilities of the Company +and the other guarantors arising under the 2010 Credit Agreement +and other loan documents. Such guarantees also cover obligations +of the Company and any subsidiary of the Company arising under +any interest rate swap contract with any person while such +person is a lender or affiliate of a lender under the 2010 +Credit Agreement. +The 2010 Credit Agreement contains customary representations, +warranties, indemnities and affirmative and negative covenants. +The 2010 Credit Agreement also requires compliance with two +financial covenants. The Company must not permit its debt to +capitalization ratio to exceed 45% at any time. The 2010 Credit +Agreement generally defines the debt to capitalization ratio as +the ratio of (a) total borrowed money indebtedness to +(b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. The Company also must +not permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit +Agreement generally defines the interest coverage ratio as the +ratio of earnings before interest, taxes, depreciation and +amortization (“EBITDA”) of the four prior fiscal +quarters to interest charges for the same period. The Company +does not expect that the restrictions and covenants will impact +its ability to operate or react to opportunities that might +arise. +As of December 31, 2010, the Company had $98.8 million +principal amount outstanding under the term loan facility at an +interest rate of 3.125% and no borrowings outstanding under the +revolving credit facility. The Company had $41.2 million in +letters of credit outstanding at December 31, 2010 and, as +a result, had available borrowing capacity of approximately +$359 million at that date. +Senior Notes — On October 5, 2010, the +Company completed the issuance and sale of $300 million in +aggregate principal amount of its 4.97% Series A Senior +Notes due October 5, 2020 (the “Notes”) in a +private placement. A portion of the proceeds from the Notes was +used to repay a $200 million borrowing on the +Company’s revolving credit facility, which had been drawn +to fund a portion of the acquisition that closed on +October 1, 2010 as discussed in Note 3. The Notes are +senior unsecured obligations of the Company which rank equally +in right of payment with all other unsubordinated indebtedness +of the Company. The Notes are guaranteed on a senior unsecured +basis by each of the existing domestic subsidiaries of the +Company other than immaterial subsidiaries. +The Notes bear interest at a rate of 4.97% per annum and were +priced at 100% of the principal amount of the Notes. The Company +will pay interest on the Notes on April 5 and October 5 of each +year commencing on April 5, +F-18 +2011. The Notes will mature on October 5, 2020. The Notes +are prepayable at the Company’s option, in whole or in +part, provided that in the case of a partial prepayment, +prepayment must be in an amount not less than 5% of the +aggregate principal amount of the Notes then outstanding, at any +time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment +date, plus a “make-whole” premium as specified in the +note purchase agreement. The Company must offer to prepay the +Notes upon the occurrence of any change of control. In addition, +the Company must offer to prepay the Notes upon the occurrence +of certain asset dispositions if the proceeds therefrom are not +timely reinvested in productive assets. If any offer to prepay +is accepted, the purchase price of each prepaid Note is 100% of +the principal amount thereof, plus accrued and unpaid interest +thereon to the prepayment date. +The note purchase agreement requires compliance with two +financial covenants. The Company must not permit its debt to +capitalization ratio to exceed 50% at any time. The note +purchase agreement generally defines the debt to capitalization +ratio as the ratio of (a) total borrowed money indebtedness +to (b) the sum of such indebtedness plus consolidated net +worth, with consolidated net worth determined as of the last day +of the most recently ended fiscal quarter. The Company also must +not permit the interest coverage ratio as of the last day of a +fiscal quarter to be less than 2.50 to 1.00. The note purchase +agreement generally defines the interest coverage ratio as the +ratio for the four prior quarters of EBITDA to interest charges +for that same period. The Company does not expect that the +restrictions and covenants will impair its ability to operate or +react to opportunities that might arise. +Events of default under the note purchase agreement include +failure to pay principal or interest when due, failure to comply +with the financial and operational covenants, a cross default +event, a judgment in excess of a threshold event, the guaranty +agreement ceasing to be enforceable, the occurrence of certain +ERISA events, a change of control event and bankruptcy and other +insolvency events. If an event of default occurs and is +continuing, then holders of a majority in principal amount of +the Notes have the right to declare all the Notes +then-outstanding to be immediately due and payable. In addition, +if the Company defaults in payments on any Note, then until such +defaults are cured, the holder thereof may declare all the Notes +held by it to be immediately due and payable. +During the year ended December 31, 2010, the Company +incurred approximately $10.8 million in debt issuance costs +in connection with the 2010 Credit Agreement and the Senior +Notes discussed above. These costs were deferred and will be +recognized as interest expense over the term of the underlying +debt. For the year ended December 31, 2010, interest +expense related to the amortization of debt issuance costs for +the 2010 Credit Agreement and the Senior Notes was approximately +$1.1 million. +Presented below is a schedule of the principal repayment +requirements of long-term debt by fiscal year as of +December 31, 2010 (in thousands): +Year ending December 31, +2011 +$ +6,250 +2012 +10,000 +2013 +12,500 +2014 +70,000 +2015 +— +Thereafter +300,000 +Total +$ +398,750 +9. +Commitments, +Contingencies and Other Matters +Commitments — As of December 31, 2010, the +Company maintained letters of credit in the aggregate amount of +$41.2 million for the benefit of various insurance +companies as collateral for retrospective premiums and retained +losses which could become payable under the terms of the +underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically +renewed. As of December 31, 2010, no amounts had been drawn +under the letters of credit. +As of December 31, 2010, the Company had commitments to +purchase approximately $267 million of major equipment. +F-19 +Contingencies — The Company’s contract +services operations are subject to inherent risks, including +blowouts, cratering, fire and explosions which could result in +personal injury or death, suspended drilling operations, damage +to, or destruction of equipment, damage to producing formations +and pollution or other environmental hazards. +As a protection against these hazards, the Company maintains, +subject to a $2.0 million self-insured retention, general +liability insurance coverage, with $10.0 million of +aggregate coverage and excess liability and umbrella coverages +up to $200 million per occurrence and in the aggregate. The +Company maintains a $1.0 million per occurrence deductible +on its workers’ compensation, and automobile liability +insurance coverages. Accrued expenses related to insurance +claims are set forth in Note 6. +The Company believes it is adequately insured for bodily injury +and property damage to others with respect to its operations. +However, such insurance may not be sufficient to protect the +Company against liability for all consequences of personal +injury, well disasters, extensive fire damage, or damage to the +environment. The Company also carries insurance to cover +physical damage to, or loss of, its equipment. However, it does +not cover the full replacement cost of the equipment and the +Company does not carry insurance against loss of earnings +resulting from such damage. There can be no assurance that such +insurance coverage will always be available on terms that are +satisfactory to the Company, if at all. +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that +the outcome of these proceedings, either individually or in the +aggregate, will have a material adverse effect on its financial +condition, results of operations or cash flows. +Other Matters — The Company has Change in +Control Agreements with its Chairman of the Board, Chief +Executive Officer, two Senior Vice Presidents and its General +Counsel (the “Key Employees”). Each Change in Control +Agreement generally has an initial term with automatic +twelve-month renewals unless the Company notifies the Key +Employee at least ninety days before the end of such renewal +period that the term will not be extended. If a change in +control of the Company occurs during the term of the agreement +and the Key Employee’s employment is terminated (i) by +the Company other than for cause or other than automatically as +a result of death, disability or retirement, or (ii) by the +Key Employee for good reason (as those terms are defined in the +Change in Control Agreements), then the Key Employee shall +generally be entitled to, among other things: +• +a bonus payment equal to the greater of the highest bonus paid +after the Change in Control Agreement was entered into and the +average of the two annual bonuses earned in the two fiscal years +immediately preceding a change in control (such bonus payment +prorated for the portion of the fiscal year preceding the +termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the +Board and Chief Executive Officer), 2 times (in the case of the +Senior Vice Presidents) or 1.5 times (in the case of the General +Counsel) of the sum of (i) the highest annual salary in +effect for such Key Employee and (ii) the average of the +three annual bonuses earned by the Key Employee for the three +fiscal years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up +to three years (in the case of the Chairman of the Board and +Chief Executive Officer) or two years (in the case of the Senior +Vice Presidents and General Counsel). +Each Change in Control Agreement provides the Key Employee with +a full +gross-up +payment for any excise taxes imposed on payments and benefits +received under the Change in Control Agreements or otherwise, +including other taxes that may be imposed as a result of the +gross-up +payment. +F-20 +10. +Stockholders’ +Equity +Cash Dividends — The Company paid cash +dividends during the years ended December 31, 2008, 2009 +and 2010 as follows: +Per Share +Total +(in thousands) +2008: +Paid on March 28, 2008 +$ +0.12 +$ +18,493 +Paid on June 27, 2008 +0.16 +25,011 +Paid on September 29, 2008 +0.16 +24,803 +Paid on December 29, 2008 +0.16 +24,558 +Total cash dividends +$ +0.60 +$ +92,865 +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +2010: +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +On February 2, 2011, the Company’s Board of Directors +approved a cash dividend on its common stock in the amount of +$0.05 per share to be paid on March 30, 2011 to holders of +record as of March 15, 2011. The amount and timing of all +future dividend payments, if any, is subject to the discretion +of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of +the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors +approved a stock buyback program authorizing purchases of up to +$250 million of the Company’s common stock in open +market or privately negotiated transactions. During the year +ended December 31, 2008, the Company purchased +3,502,047 shares of its common stock under the program at a +cost of approximately $66.3 million. During the year ended +December 31, 2009, the Company purchased 5,715 shares +of its common stock under the program at a cost of approximately +$79,000. During the year ended December 31, 2010, the +Company purchased 8,743 shares of its common stock under +the program at a cost of approximately $123,000. As of +December 31, 2010, the Company is authorized to purchase +approximately $113 million of the Company’s +outstanding common stock under the program. Shares purchased +under the program are accounted for as treasury stock. +The Company purchased 117,083, 114,983 and 152,235 shares +of treasury stock from employees during 2010, 2009 and 2008, +respectively. These shares were purchased at fair market value +upon the vesting of restricted stock to provide the employees +with the funds necessary to satisfy payroll tax withholding +obligations. The total purchase price for these shares was +approximately $1.7 million, $1.5 million and +$4.5 million in 2010, 2009 and 2008, respectively. These +purchases were made pursuant to the terms of the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to +the stock buyback program. +F-21 +11. +Stock-based +Compensation +The Company uses share-based payments to compensate employees +and non-employee directors. The Company recognizes the cost of +share-based payments under the fair-value-based method. +Share-based awards consist of equity instruments in the form of +stock options, restricted stock or restricted stock units and +have included service and, in certain cases, performance +conditions. The Company’s share-based awards also include +both cash-settled and share-settled performance unit awards. +Cash-settled performance unit awards are accounted for as +liability awards. Share-settled performance unit awards are +accounted for as equity awards. The Company issues shares of +common stock when vested stock options are exercised, when +restricted stock is granted and when restricted stock units and +share-settled performance unit awards vest. +The Company’s shareholders have approved the Patterson-UTI +Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 +Plan”), and the Board of Directors adopted a resolution +that no future grants would be made under any of the +Company’s other previously existing plans. During 2010, the +Company amended the 2005 Plan to, among other things, increase +the total number of shares authorized for grant from 10,250,000 +to 15,250,000. The Company’s share-based compensation plans +at December 31, 2010 follow: +Shares +Shares +Authorized +Awards +Available +Plan Name +for Grant +Outstanding +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as +amended +15,250,000 +5,830,135 +5,763,314 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan, as amended (“1997 Plan”) +— +2,843,300 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (“2001 Plan”) +— +168,552 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers +the plan. +• +All employees including officers and directors are eligible for +awards. +• +The Compensation Committee determines the vesting schedule for +awards. Awards typically vest over one year for non-employee +directors and three to four years for employees. +• +The Compensation Committee sets the term of awards and no option +term can exceed 10 years. +• +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. As of December 31, 2010, +non-incentive stock options, restricted stock awards, restricted +stock units and performance unit awards had been granted under +the plan. +Options granted under the 1997 Plan typically vest over three or +five years as dictated by the Compensation Committee. These +options have terms of no more than ten years. All options were +granted with an exercise price equal to the fair market value of +the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four +years. +Options granted under the 2001 Plan typically vest over five +years as dictated by the Compensation Committee. These options +have terms of no more than 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. +Stock Options — The Company estimates the grant +date fair values of stock options using the Black-Scholes-Merton +valuation model. Volatility assumptions are based on the +historic volatility of the Company’s common stock over the +most recent period equal to the expected term of the options as +of the date the options are granted. The expected term +assumptions are based on the Company’s experience with +respect to employee stock option activity. +F-22 +Dividend yield assumptions are based on the expected dividends +at the time the options are granted. The risk-free interest rate +assumptions are determined by reference to United States +Treasury yields. Weighted-average assumptions used to estimate +grant date fair values for stock options granted in the years +ended December 31, 2010, 2009 and 2008 follow: +2010 +2009 +2008 +Volatility +45.98 +% +49.90 +% +37.04 +% +Expected term (in years) +5.00 +4.00 +4.17 +Dividend yield +1.35 +% +1.67 +% +2.27 +% +Risk-free interest rate +2.47 +% +1.67 +% +2.91 +% +Stock option activity for the year ended December 31, 2010 +follows: +Weighted-average +Shares +exercise price +Outstanding at beginning of year +6,841,770 +$ +20.17 +Granted +1,016,250 +$ +14.85 +Exercised +(60,918 +) +$ +8.61 +Cancelled +(10,000 +) +$ +13.17 +Expired +(77,000 +) +$ +19.46 +Outstanding at end of year +7,710,102 +$ +19.58 +Exercisable at end of year +6,095,018 +$ +20.81 +Options outstanding at December 31, 2010 have an aggregate +intrinsic value of approximately $30.0 million and a +weighted-average remaining contractual term of 5.6 years. +Options exercisable at December 31, 2010 have an aggregate +intrinsic value of approximately $18.7 million and a +weighted-average remaining contractual term of 4.8 years. +Additional information with respect to options granted, vested +and exercised during the years ended December 31, 2010, +2009 and 2008 follows: +2010 +2009 +2008 +Weighted-average grant date fair value of stock options granted +(per share) +$ +5.69 +$ +4.71 +$ +7.20 +Grant date fair value of stock options vested during the year +(in thousands) +$ +5,553 +$ +6,973 +$ +6,761 +Aggregate intrinsic value of stock options exercised (in +thousands) +$ +523 +$ +510 +$ +45,240 +As of December 31, 2010, options to purchase +1,615,084 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. +Additional information as of December 31, 2010 with respect +to these non-vested options follows: +Aggregate intrinsic value +$11.3 million +Weighted-average remaining contractual term +8.88 years +Weighted-average remaining expected term +3.56 years +Weighted-average remaining vesting period +1.88 years +Unrecognized compensation cost +$7.1 million +Restricted Stock — For all restricted stock +awards to date, shares of common stock were issued when the +awards were made. Non-vested shares are subject to forfeiture +for failure to fulfill service conditions and, in certain cases, +performance conditions. Non- forfeitable dividends are paid on +non-vested shares of restricted stock. The Company uses the +straight-line method to recognize periodic compensation cost +over the vesting period. +F-23 +Restricted stock activity for the year ended December 31, +2010 follows: +Weighted- +average +Grant Date +Shares +Fair Value +Non-vested restricted stock outstanding at beginning of year +1,231,901 +$ +21.67 +Granted +699,825 +$ +14.68 +Vested +(758,394 +) +$ +23.48 +Forfeited +(59,281 +) +$ +21.63 +Non-vested restricted stock outstanding at end of year +1,114,051 +$ +16.05 +As of December 31, 2010, approximately 976,000 shares +of non-vested restricted stock outstanding are expected to vest. +Additional information as of December 31, 2010 with respect +to these non-vested shares follows: +Aggregate intrinsic value +$21.0 million +Weighted-average remaining vesting period +1.90 years +Unrecognized compensation cost +$12.2 million +Restricted Stock Units — For all restricted +stock unit awards made to date, shares of common stock are not +issued until the units vest. Restricted stock units are subject +to forfeiture for failure to fulfill service conditions. +Non-forfeitable cash dividend equivalents are paid on non-vested +restricted stock units. +Restricted stock unit activity for the year ended +December 31, 2010 follows: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested restricted stock units outstanding at beginning of +year +16,167 +$ +26.81 +Granted +9,000 +$ +13.81 +Vested +(7,333 +) +$ +28.08 +Forfeited +— +$ +— +Non-vested restricted stock units outstanding at end of year +17,834 +$ +19.73 +Performance Unit Awards. On April 28, +2009, the Company granted cash-settled performance unit awards +to certain executive officers (the “2009 Performance +Units”). The 2009 Performance Units provide for those +executive officers to receive a cash payment upon the +achievement of certain performance goals established by the +Company during a specified period. The performance period for +the 2009 Performance Units is the period from April 1, 2009 +through March 31, 2012, but can extend through +March 31, 2014 in certain circumstances. The performance +goals for the 2009 Performance Units are tied to the +Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee of the Board of +Directors. These goals are considered to be market conditions +under the relevant accounting standards and the market +conditions are factored into the determination of the fair value +of the performance units. Generally, the recipients will receive +a base payment if the Company’s total shareholder return is +positive and, when compared to the peer group, is at or above +the 25 th +percentile but less than the +50 th +percentile; two times the base if at or above the 50th +percentile but less than the +75 th +percentile, and four times the base if at the 75th percentile or +higher. The total base amount with respect to the 2009 +Performance Units is approximately $1.7 million. Because +the 2009 Performance Units are to be settled in cash at the end +of the performance period, they are accounted for as liability +awards and the Company’s pro-rated obligation is measured +at estimated fair value at the end of each reporting period +using a Monte Carlo simulation model. As of December 31, +2010 this pro-rated obligation was approximately +$2.3 million and is included in the caption +“other” in the liabilities section of the consolidated +balance sheet. Compensation expense associated with the 2009 +Performance Units was approximately $1.5 million and +$859,000 for the years ended December 31,2010 and 2009, +respectively. +F-24 +On April 27, 2010, the Company granted stock-settled +performance unit awards to certain executive officers (the +“2010 Performance Units”). The 2010 Performance Units +provide for those executive officers to receive a grant of +shares of stock upon the achievement of certain performance +goals established by the Company during a specified period. The +performance period for the 2010 Performance Units is the period +from April 1, 2010 through March 31, 2013, but can +extend through March 31, 2015 in certain circumstances. The +performance goals for the 2010 Performance Units are tied to the +Company’s total shareholder return for the performance +period as compared to total shareholder return for a peer group +determined by the Compensation Committee of the Board of +Directors. These goals are considered to be market conditions +under the relevant accounting standards and the market +conditions are factored into the determination of the fair value +of the performance units. Generally, the recipients will receive +a base number of shares if the Company’s total shareholder +return is positive and, when compared to the peer group, is at +or above the 25th percentile but less than the 50th percentile, +two times the base if at or above the 50th percentile but less +than the 75th percentile, and four times the base if at the 75th +percentile or higher. The grant of shares when achievement is +between the 25th and 75th percentile will be determined on a +pro-rata basis. The total base number of shares with respect to +the 2010 Performance Units is 89,375 shares. Because the +2010 Performance Units are stock-settled awards, they are +accounted for as equity awards and measured at fair value on the +date of grant. The fair value of the 2010 Performance Units as +of the date of grant was approximately $3.1 million using a +Monte Carlo simulation model. This amount will be recognized on +a straight-line basis over the performance period. Compensation +expense associated with the 2010 Performance Units was +approximately $779,000 for the year ended December 31, 2010. +Dividends on Equity Awards — Non-forfeitable +cash dividends and dividend equivalents paid on equity awards +are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for +the portion of restricted stock awards expected to vest. +• +Dividends are recognized as additional compensation cost for the +portion of restricted stock awards that are not expected to vest +or that ultimately do not vest. +• +Dividend equivalents are recognized as additional compensation +cost for restricted stock units. +12. +Leases +The Company incurred rent expense of $18.1 million, +$11.9 million and $31.5 million for the years 2010, +2009 and 2008, respectively. Rent expense is primarily related +to short-term equipment rentals that are generally passed +through to customers. The Company’s obligations under +non-cancelable operating lease agreements are not material to +its operations or cash flows. +F-25 +13. +Income +Taxes +Components of the income tax provision applicable to Federal, +state and foreign income taxes for the years ended +December 31, 2010, 2009 and 2008 are as follows (in +thousands): +2010 +2009 +2008 +Federal income tax expense (benefit): +Current +$ +(77,310 +) +$ +(117,493 +) +$ +117,367 +Deferred +145,198 +103,574 +57,879 +67,888 +(13,919 +) +175,246 +State income tax expense (benefit): +Current +19 +(1,883 +) +6,475 +Deferred +3,246 +(1,875 +) +7,070 +3,265 +(3,758 +) +13,545 +Foreign income tax expense (benefit): +Current +2,657 +338 +4,256 +Deferred +(954 +) +(256 +) +443 +1,703 +82 +4,699 +Total income tax expense (benefit): +Current +(74,634 +) +(119,038 +) +128,098 +Deferred +147,490 +101,443 +65,392 +Total income tax expense (benefit) +$ +72,856 +$ +(17,595 +) +$ +193,490 +The difference between the statutory Federal income tax rate and +the effective income tax rate for the years ended +December 31, 2010, 2009 and 2008 is summarized as follows: +2010 +2009 +2008 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +1.1 +4.7 +1.7 +Permanent differences +2.3 +(5.7 +) +(1.2 +) +Other, net +(0.2 +) +0.1 +(0.2 +) +Effective tax rate +38.2 +% +34.1 +% +35.3 +% +For 2008, the permanent difference indicated above was largely +attributable to the Company’s Domestic Production +Activities Deduction. The Domestic Production Activities +Deduction was enacted as part of the American Jobs Creation Act +of 2004 (as revised by the Emergency Economic Stabilization Act +of 2008,) and allows a deduction of 6% in both 2008 and 2009 and +9% in 2010 and thereafter on the lesser of qualified production +activities income or taxable income. The permanent differences +for 2010 and 2009 reflect the recapture of a portion of this +deduction due to the planned carryback of the 2010 net +operating loss to prior years and the carryback of the 2009 net +operating loss to prior years. This recapture resulted in a +negative effective rate impact in 2009 due to the Company having +a loss before income taxes in that year. +F-26 +The tax effect of significant temporary differences representing +deferred tax assets and liabilities and changes therein were as +follows (in thousands): +December 31, +Net +December 31, +Net +December 31, +Net +December 31, +2010 +Change +2009 +Change +2008 +Change +2007 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +— +$ +— +$ +— +$ +— +$ +— +$ +(374 +) +$ +374 +Workers’ compensation allowance +23,290 +(1,334 +) +24,624 +(1,360 +) +25,984 +(602 +) +26,586 +Other +18,654 +(962 +) +19,616 +(2,735 +) +22,351 +3,287 +19,064 +41,944 +(2,296 +) +44,240 +(4,095 +) +48,335 +2,311 +46,024 +Non-current: +Net operating loss carryforwards +6,465 +1,593 +4,872 +4,872 +— +— +— +AMT credit +— +— +— +— +— +(118 +) +118 +Expense associated with employee stock options +11,252 +2,123 +9,129 +2,500 +6,629 +1,381 +5,248 +Federal benefit of foreign deferred tax liabilities +— +(9,160 +) +9,160 +(256 +) +9,416 +443 +8,973 +Federal benefit of state deferred tax liabilities +13,155 +3,383 +9,772 +2,702 +7,070 +1,643 +5,427 +Other +16,031 +6,546 +9,485 +4,120 +5,365 +614 +4,751 +46,903 +4,485 +42,418 +13,938 +28,480 +3,963 +24,517 +Total deferred tax assets +88,847 +2,189 +86,658 +9,843 +76,815 +6,274 +70,541 +Deferred tax liabilities: +Current: +Other +(15,129 +) +(3,766 +) +(11,363 +) +1,044 +(12,407 +) +(1,753 +) +(10,654 +) +Non-current: +Property and equipment basis difference +(546,655 +) +(133,542 +) +(413,113 +) +(110,786 +) +(302,327 +) +(70,362 +) +(231,965 +) +Other +(11,670 +) +(709 +) +(10,961 +) +(7,091 +) +(3,870 +) +8,172 +(12,042 +) +(558,325 +) +(134,251 +) +(424,074 +) +(117,877 +) +(306,197 +) +(62,190 +) +(244,007 +) +Total deferred tax liabilities +(573,454 +) +(138,017 +) +(435,437 +) +(116,833 +) +(318,604 +) +(63,943 +) +(254,661 +) +Net deferred tax liability +$ +(484,607 +) +$ +(135,828 +) +$ +(348,779 +) +$ +(106,990 +) +$ +(241,789 +) +$ +(57,669 +) +$ +(184,120 +) +In assessing the realizability of deferred tax assets, +management considers whether it is more likely than not that +some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is +dependent upon the generation of future taxable income during +the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of +deferred tax liabilities, projected future taxable income and +tax planning strategies in making this assessment. The Company +expects the deferred tax assets at December 31, 2010 and +2009 to be realized as a result of the reversal of existing +taxable temporary differences giving rise to deferred tax +liabilities and the generation of taxable income; therefore, no +valuation allowance is considered necessary. +Other deferred tax assets consist primarily of the tax effect of +various allowance accounts and tax-deferred expenses expected to +generate future tax benefit of approximately $35 million. +Other deferred tax liabilities consist primarily of the tax +effect of receivables from insurance companies and tax-deferred +income not yet recognized for tax purposes. +For income tax purposes, the Company generated approximately +$221 million of Federal net operating losses and +approximately $71.3 million of state net operating losses +during the year ended December 31, 2010. Of these amounts, +approximately $257 million will be carried back to prior +years, and the remaining balance can be carried +F-27 +forward to future years. Net operating losses that can be +carried forward, if unused, are scheduled to expire as follows: +2014 — $9 million; 2015 — +$5 million; 2019 — $12 million; +2029 — $57 million and 2030 - $18 million. +As of December 31, 2010, the Company had no unrecognized +tax benefits. The Company has established a policy to account +for interest and penalties related to uncertain income tax +positions as operating expenses. As of December 31, 2010, +the tax years ended December 31, 2007 through +December 31, 2009 are open for examination by +U.S. taxing authorities. As of December 31, 2010, the +tax years ended December 31, 2006 through December 31, +2009 are open for examination by Canadian taxing authorities. +On January 1, 2010, the Company converted its Canadian +operations from a Canadian branch to a controlled foreign +corporation for Federal income tax purposes. Because the +statutory tax rates in Canada are lower than those in the United +States, this transaction triggered a $5.1 million reduction +in deferred tax liabilities, which is being amortized as a +reduction to deferred income tax expense over the weighted +average remaining useful life of the Canadian assets. +As a result of the above conversion, the Company’s Canadian +assets are no longer subject to United States taxation, provided +that the related unremitted earnings are permanently reinvested +in Canada. Effective January 1, 2010, the Company has +elected to permanently reinvest these unremitted earnings in +Canada, and intends to do so for the foreseeable future. As a +result, no deferred United States Federal or state income taxes +have been provided on such unremitted foreign earnings, which +totaled approximately $6.3 million as of December 31, +2010. +14. +Employee +Benefits +The Company maintains a 401(k) plan for all eligible employees. +The Company’s operating results include expenses of +approximately $3.1 million in 2010, $2.8 million in +2009 and $4.5 million in 2008 for the Company’s cash +contributions to the plan. +15. +Business +Segments +The Company’s revenues, operating profits and identifiable +assets are primarily attributable to three business segments: +(i) contract drilling of oil and natural gas wells, +(ii) pressure pumping services and (iii) the +investment, on a working interest basis, in oil and natural gas +properties. Each of these segments represents a distinct type of +business. These segments have separate management teams which +report to the Company’s chief operating decision maker. The +results of operations in these segments are regularly reviewed +by the chief operating decision maker for purposes of +determining resource allocation and assessing performance. As +discussed in Note 2, in January 2010 the Company exited the +drilling and completion fluids services business which +previously was reported as a business segment. Operating results +for that business for the years ended December 31, 2010, +2009 and 2008 are presented as discontinued operations in the +consolidated statements of operations. Also included in +discontinued operations for the year ended December 31, +2010 are the operating results for an electric wireline business +that was acquired on October 1, 2010 and sold in January +2011. +Contract Drilling — The Company markets its +contract drilling services to major and independent oil and +natural gas operators. As of December 31, 2010, the Company +had 356 marketable land-based drilling rigs, of which 73 of the +drilling rigs were based in west Texas and southeastern New +Mexico; 97 in north central and east Texas, northern Louisiana +and Mississippi; 58 in the Rocky Mountain region (Colorado, +Utah, Wyoming, Montana and North Dakota); 51 in south Texas and +southern Louisiana; 32 in the Texas panhandle, Oklahoma and +Arkansas; 25 in the Appalachian Basin and 20 in western Canada. +For the years ended December 31, 2010, 2009 and 2008, +contract drilling revenue earned in Canada was +$65.7 million, $45.4 million and $88.5 million, +respectively. Additionally, long-lived assets within the +contract drilling segment located in Canada totalled +$70.7 million and $69.2 million as of +December 31, 2010 and 2009, respectively. +Pressure Pumping — The Company provides +pressure pumping services to oil and natural gas operators +primarily in Texas and the Appalachian Basin. Pressure pumping +services are primarily well stimulation and cementing for the +completion of new wells and remedial work on existing wells. +Well stimulation involves processes inside a well designed to +enhance the flow of oil, natural gas, or other desired +substances from the well. +F-28 +Cementing is the process of inserting material between the hole +and the pipe to center and stabilize the pipe in the hole. +Oil and Natural Gas — The Company owns and +invests in oil and natural gas assets as a working interest +owner. The Company’s oil and natural gas interests are +located primarily in Texas and New Mexico. +The following tables summarize selected financial information +relating to the Company’s business segments (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Revenues: +Contract drilling +$ +1,085,722 +$ +600,423 +$ +1,808,600 +Pressure pumping +350,608 +161,441 +217,494 +Oil and natural gas +30,425 +21,218 +42,360 +Total segment revenues +1,466,755 +783,082 +2,068,454 +Elimination of intercompany revenues(a) +(3,824 +) +(1,136 +) +(4,574 +) +Total revenues +$ +1,462,931 +$ +781,946 +$ +2,063,880 +Income (loss) from continuing operations before income taxes: +Contract drilling +$ +140,483 +$ +(11,219 +) +$ +520,636 +Pressure pumping +62,194 +1,017 +42,019 +Oil and natural gas +12,455 +950 +13,711 +215,132 +(9,252 +) +576,366 +Corporate and other +(37,019 +) +(35,577 +) +(34,596 +) +Net (loss) gain on asset disposals(b) +22,812 +(3,385 +) +4,163 +Interest income +1,674 +381 +1,553 +Interest expense +(12,772 +) +(4,148 +) +(630 +) +Other +927 +426 +502 +Income (loss) from continuing operations before income taxes +$ +190,754 +$ +(51,555 +) +$ +547,358 +Identifiable assets: +Contract drilling +$ +2,678,250 +$ +2,129,567 +$ +2,255,421 +Pressure pumping +533,597 +213,094 +210,805 +Oil and natural gas +36,508 +25,355 +31,760 +Corporate and other(c) +174,676 +294,136 +214,831 +Total assets +$ +3,423,031 +$ +2,662,152 +$ +2,712,817 +Depreciation, depletion, amortization and impairment: +Contract drilling +$ +280,458 +$ +248,424 +$ +239,700 +Pressure pumping +40,724 +27,589 +19,600 +Oil and natural gas +10,950 +12,927 +15,856 +Corporate and other +1,361 +907 +834 +Total depreciation, depletion, amortization and impairment +$ +333,493 +$ +289,847 +$ +275,990 +F-29 +Years Ended December 31, +2010 +2009 +2008 +Capital expenditures: +Contract drilling +$ +655,550 +$ +395,376 +$ +360,645 +Pressure pumping +51,064 +43,144 +61,289 +Oil and natural gas +23,067 +7,341 +22,981 +Corporate and other +8,409 +6,785 +511 +Total capital expenditures +$ +738,090 +$ +452,646 +$ +445,426 +(a) +Includes contract drilling intercompany revenues related to +drilling services provided to the oil and natural gas +exploration and production segment. +(b) +Net gains or losses associated with the disposal of assets +relate to corporate strategy decisions of the executive +management group. Accordingly, the related gains or losses have +been separately presented and excluded from the results of +specific segments. +(c) +Corporate and other assets primarily include identifiable assets +associated with assets held for sale as well as cash on hand, +income taxes receivable and certain deferred Federal income tax +assets. +16. +Concentrations +of Credit Risk +Financial instruments which potentially subject the Company to +concentrations of credit risk consist primarily of demand +deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial +institutions. At December 31, 2010 and 2009, the +Company’s demand deposits and temporary cash investments +consisted of the following (in thousands): +2010 +2009 +Deposits in FDIC and SIPC-insured institutions under insurance +limits +$ +1,523 +$ +20,543 +Deposits in FDIC and SIPC-insured institutions over insurance +limits +51,625 +47,376 +Deposits in foreign banks +11,533 +4,383 +64,681 +72,302 +Less outstanding checks and other reconciling items +(37,069 +) +(22,425 +) +Cash and cash equivalents +$ +27,612 +$ +49,877 +Concentrations of credit risk with respect to trade receivables +are primarily focused on companies involved in the exploration +and development of oil and natural gas properties. The +concentration is somewhat mitigated by the diversification of +customers for which the Company provides services. As is general +industry practice, the Company typically does not require +customers to provide collateral. No significant losses from +individual customers were experienced during the years ended +December 31, 2010, 2009 or 2008. The Company recorded a +provision for bad debts for 2010, 2009 and 2008 of +$(2.0) million, $3.8 million and $4.4 million, +respectively. +The carrying values of cash and cash equivalents, trade +receivables and accounts payable approximate fair value due to +the short-term maturity of these items. The carrying value of +the balance outstanding under the term loan facility at +December 31, 2010 approximates fair value as it has a +floating interest rate that adjusts at each quarterly interest +payment date. The fair value of the 4.97% Series A Senior +Notes at December 31, 2010 was approximately +$290 million. +F-30 +17. +Quarterly +Financial Information (in thousands, except per share amounts) +(unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2009 +Operating revenues +$ +268,209 +$ +140,497 +$ +159,671 +$ +213,569 +Operating income (loss) +25,154 +(25,855 +) +(24,619 +) +(22,894 +) +Income (loss) from continuing operations, net of income taxes +15,835 +(16,891 +) +(16,814 +) +(16,090 +) +Income (loss) from discontinued operations, net of income taxes +368 +(852 +) +(1,766 +) +(2,080 +) +Net income (loss) +16,203 +(17,743 +) +(18,580 +) +(18,170 +) +Basic income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income +$ +0.11 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +Diluted income (loss) per common share: +From continuing operations +$ +0.10 +$ +(0.11 +) +$ +(0.11 +) +$ +(0.11 +) +From discontinued operations +$ +0.00 +$ +(0.01 +) +$ +(0.01 +) +$ +(0.01 +) +Net income +$ +0.11 +$ +(0.12 +) +$ +(0.12 +) +$ +(0.12 +) +2010 +Operating revenues +$ +271,598 +$ +306,992 +$ +378,663 +$ +505,678 +Operating income +7,831 +45,757 +52,509 +94,828 +Income (loss) from continuing operations, net of income taxes +4,186 +29,528 +29,374 +54,810 +Loss from discontinued operations, net of income taxes +— +— +— +(956 +) +Net income +4,186 +29,528 +29,374 +53,854 +Basic income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.36 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +Diluted income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +As discussed in Note 2, the Company exited the drilling and +completion fluids services business in January 2010 and sold a +recently acquired wireline business in January 2011. The results +of operations related to those businesses have been reclassified +and presented as discontinued operations in the quarterly +financial information above. +F-31 +Schedule +PATTERSON-UTI +ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND +QUALIFYING ACCOUNTS +Charged to +Beginning +Costs and +Ending +Description +Balance +Expenses +Deductions(1) +Balance +(In thousands) +Year Ended December 31, 2010 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,911 +$ +(2,000 +) +$ +3,797 +$ +5,114 +Year Ended December 31, 2009 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +9,330 +$ +4,700 +$ +3,119 +$ +10,911 +Year Ended December 31, 2008 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,014 +$ +4,350 +$ +5,034 +$ +9,330 +(1) +Consists of uncollectible accounts written off. +S-1 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the +Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has +duly caused this Report on +Form 10-K +to be signed on its behalf by the undersigned, thereunto duly +authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas +J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 14, 2011 +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 +February 14, 2011. +Signature +Title +/s/ Mark +S. Siegel +Mark +S. Siegel +Chairman of the Board +/s/ Douglas +J. Wall +Douglas +J. Wall +(Principal Executive Officer) +President and Chief Executive Officer +/s/ John +E. Vollmer III +John +E. Vollmer III +(Principal Financial Officer) +Senior Vice President — Corporate Development, Chief +Financial Officer and Treasurer +/s/ Gregory +W. Pipkin +Gregory +W. Pipkin +(Principal Accounting Officer) +Chief Accounting Officer and Assistant Secretary +/s/ Kenneth +N. Berns +Kenneth +N. Berns +Senior Vice President and Director +/s/ Charles +O. Buckner +Charles +O. Buckner +Director +/s/ Curtis +W. Huff +Curtis +W. Huff +Director +/s/ Terry +H. Hunt +Terry +H. Hunt +Director +/s/ Kenneth +R. Peak +Kenneth +R. Peak +Director +/s/ Cloyce +A. Talbott +Cloyce +A. Talbott +Director +EXHIBIT INDEX +2 +.1 +Asset Purchase Agreement dated July 2, 2010 by and among +Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a +Universal Pressure Pumping, Inc.), Key Energy Pressure Pumping +Services, LLC, Key Electric Wireline Services, LLC and Key +Energy Services, Inc. (filed July 6, 2010 as +Exhibit 2.1 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +2 +.2 +Letter Agreement dated September 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.2 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +2 +.3 +Letter Agreement dated October 1, 2010 by and among +Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., +Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline +Services LLC (filed November 1, 2010 as Exhibit 2.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2010 and +incorporated herein by reference). +3 +.1 +Restated Certificate of Incorporation, as amended (filed +August 9, 2004 as Exhibit 3.1 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.2 +Amendment to Restated Certificate of Incorporation, as amended +(filed August 9, 2004 as Exhibit 3.2 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference). +3 +.3 +Second Amended and Restated Bylaws (filed August 6, 2007 as +Exhibit 3.3 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +4 +.1 +Rights Agreement dated January 2, 1997, between Patterson +Energy, Inc. and Continental Stock Transfer & +Trust Company (filed January 14, 1997 as +Exhibit 2 to the Company’s Registration Statement on +Form 8-A +and incorporated herein by reference). +4 +.2 +Amendment to Rights Agreement dated as of October 23, 2001 +(filed October 31, 2001 as Exhibit 3.4 to the +Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2001 and +incorporated herein by reference). +4 +.3 +Restated Certificate of Incorporation, as amended (See +Exhibits 3.1 and 3.2). +4 +.4 +Registration Rights Agreement with Bear, Stearns and Co. Inc., +dated March 25, 1994, as assigned to REMY Capital Partners +III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on +Form 10-K +for the fiscal year ended December 31, 2001 and +incorporated herein by reference). +10 +.1 +For additional material contracts, see Exhibits 4.1, 4.2 +and 4.4. +10 +.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term +Incentive Plan (filed November 27, 2002 as Exhibit 4.4 +to Post Effective Amendment No. 1 to the Company’s +Registration Statement on +Form S-8 +(File +No. 333-60470) +and incorporated herein by reference).* +10 +.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term +Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2003 and +incorporated herein by reference).* +10 +.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated +1997 Long-Term Incentive Plan (filed August 9, 2004 as +Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2004 and +incorporated herein by reference).* +10 +.5 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on +February 4, 2004 as Exhibit 10.2 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.6 +Employment Agreement, dated as of September 1, 2007 between +Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on +September 24, 2007 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.7 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s +Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.8 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of January 29, 2004, by and between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +on February 4, 2004 as Exhibit 10.7 to the +Company’s Annual Report on +Form 10-K +for the year ended December 31, 2003 and incorporated +herein by reference).* +10 +.9 +Form of Letter Agreement regarding termination, effective as of +January 29, 2004, entered into by Patterson-UTI Energy, +Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. +Vollmer III (filed 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).* +10 +.10 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +including Form of Executive Officer Restricted Stock Award +Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement +and Form of Non-Employee Director Stock Option Agreement (filed +June 21, 2005 as Exhibit 10.1 to the Company’s +Current Report on +Form 8-K, +and incorporated herein by reference).* +10 +.11 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to +the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.12 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed June 6, 2008 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.13 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.1 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.14 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 +Long-Term Incentive Plan (filed April 27, 2010 as +Exhibit 10.2 to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.15 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed April 27, 2010 as Exhibit 10.3 +to the Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.16 +Form of Cash-Settled Performance Unit Award Agreement pursuant +to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, +as amended from time to time (filed February 19, 2010 as +Exhibit 10.9 to the Company’s Annual Report on +Form 10-K +for the year ended December 31, 2009 and incorporated +herein by reference).* +10 +.17 +Form of Amendment to Cash-Settled Performance Unit Award +Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to +the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended March 31, 2010 and +incorporated herein by reference).* +10 +.18 +Form of Share-Settled Performance Unit Award Agreement under the +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed +August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended June 30, 2010 and +incorporated herein by reference).* +10 +.19 +Form of Indemnification Agreement entered into by Patterson-UTI +Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, +Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. +Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, +Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 +as Exhibit 10.11 to the Company’s Annual Report on +Form 10-K, +as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10 +.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of August 31, 2007, by and between +Patterson-UTI Energy, Inc. and Douglas J. Wall (filed +September 4, 2007 as Exhibit 10.2 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference).* +10 +.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, +effective as of November 2, 2009, by and between +Patterson-UTI Energy, Inc. and Seth D. Wexler (filed +November 2, 2009 as Exhibit 10.2 to the Company’s +Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2009 and +incorporated herein by reference).* +10 +.22 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.8 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.23 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.9 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.24 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and John E. Vollmer, III, +entered into November 1, 2007 (filed November 5, 2007 +as Exhibit 10.10 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.25 +First Amendment to Change in Control Agreement Between +Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into +November 1, 2007 (filed November 5, 2007 as +Exhibit 10.11 to the Company’s Quarterly Report on +Form 10-Q +for the quarterly period ended September 30, 2007 and +incorporated herein by reference).* +10 +.26 +Letter Agreement dated February 6, 2006 between +Patterson-UTI Energy, Inc. and John E. Vollmer III (filed +May 1, 2006 as Exhibit 10.25 to the Company’s +Annual Report on +Form 10-K, +as amended, and incorporated herein by reference).* +10 +.27 +Credit Agreement dated August 19, 2010, among Patterson-UTI +Energy, Inc., as borrower, Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer and lender and +each of the other letter of credit issuer and lender parties +thereto (filed August 19, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +10 +.28 +Note Purchase Agreement dated October 5, 2010 by and among +Patterson-UTI Energy, Inc. and the purchasers named therein +(filed October 6, 2010 as Exhibit 10.1 to the +Company’s Current Report on +Form 8-K +and incorporated herein by reference). +21 +.1 +Subsidiaries of the Registrant. +23 +.1 +Consent of Independent Registered Public Accounting Firm. +31 +.1 +Certification of Chief Executive Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +31 +.2 +Certification of Chief Financial Officer pursuant to +Rule 13a-14(a)/15d-14(a) +of the Securities Exchange Act of 1934, as amended. +32 +.1 +Certification of Chief Executive Officer and Chief Financial +Officer pursuant to 18 USC Section 1350, as adopted +pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101 +The following materials from Patterson-UTI Energy, Inc.’s +Annual Report on +Form 10-K +for the year ended December 31, 2010, formatted in XBRL +(Extensible Business Reporting Language): (i) the +Consolidated Balance Sheets, (ii) the Consolidated +Statements of Income, (iii) the Consolidated Statements of +Changes in Stockholders’ Equity, (iv) the Consolidated +Statements of Cash Flows, and (v) Notes to Consolidated +Financial Statements, tagged as blocks of text. +* +Management Contract or Compensatory Plan identified as required +by Item 15(a)(3) of Form +10-K. \ No newline at end of file diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/rp_note.txt b/raw/filings/0000889900/2010/0000950123-11-013816/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2010/0000950123-11-013816/rpt_disclosure.txt b/raw/filings/0000889900/2010/0000950123-11-013816/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..76775689e19a3c731ff0682b38780ca0f751f64e --- /dev/null +++ b/raw/filings/0000889900/2010/0000950123-11-013816/rpt_disclosure.txt @@ -0,0 +1,24 @@ +related person transaction are considered, including whether +such transaction is in, or not inconsistent with, the best +interest of Patterson-UTI and whether, in appropriate cases, +such transaction is on commercial terms at least as favorable to +Patterson-UTI as would otherwise be available to or from an +unrelated third party or to Patterson-UTI’s employees +generally. Related person transactions generally include +transactions in an amount that exceeds $50,000 between +Patterson-UTI or any of its subsidiaries and an executive +officer, a director (or nominee to become director), an +immediate family member of any of the foregoing or any entity in +which any of the foregoing has a 10% or greater +37 +Table of Contents +beneficial ownership interest or in which they are an executive +officer, general partner, principal or engaged in a similar +position. Certain related person transactions have been +pre-approved under the terms of the policy, including, subject +to certain exceptions and limitations, the sale to or purchase +from Patterson-UTI of goods and services by entities related to +directors in the ordinary course of business that are immaterial +to Patterson-UTI and with respect to which the director has no +direct economic interest or decision making authority. +SECURITY \ No newline at end of file diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/filing.txt b/raw/filings/0000889900/2011/0001193125-12-052274/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..28595866dfca837a7b4d71d7061315bf9d2e6fcb --- /dev/null +++ b/raw/filings/0000889900/2011/0001193125-12-052274/filing.txt @@ -0,0 +1,6172 @@ +10-K +1 +d261327d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2011 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission File Number 0-22664 +Patterson-UTI +Energy, Inc. +(Exact name of registrant as specified in its charter) +Delaware +75-2504748 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +450 Gears Road, Suite 500, Houston, Texas +77067 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: +(281) 765-7100 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Exchange on Which Registered +Common Stock, $0.01 Par Value +The Nasdaq Global Select Market +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ or No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ or No þ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for +such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 +days. Yes þ No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ or No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in +definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller +reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer þ +Accelerated filer ¨ +Non-accelerated filer ¨ +Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). +Yes ¨ No þ +The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2011, the last business day of the registrant’s most recently +completed second fiscal quarter, was approximately $4.8 billion, calculated by reference to the closing price of $31.61 for the common stock on the Nasdaq Global Select Market on that date. +As of February 9, 2012, the registrant had outstanding 155,818,409 shares of common stock, $0.01 par value, its only class of common +stock. +Documents incorporated by reference: +Portions of the registrant’s definitive proxy statement for the 2012 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. +Table of Contents +DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking +statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, +as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue expectations and backlog; financing of operations; +continued volatility of oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; and other matters. +Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” +“estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of +similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe +are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements +may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities +and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act. +Forward-looking statements are +not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or +contribute to such differences include, but are not limited to, global economic conditions, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, +utilization, margins and planned capital expenditures, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, adverse industry conditions, adverse credit and equity market +conditions, difficulty in integrating acquisitions, shortages of labor, equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, +governmental regulation and ability to retain management and field personnel. Refer to “Risk Factors” contained in Item 1A of this Report for a more complete discussion of these and other factors that might affect our performance and +financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We +undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise, except as required by law. +PART I +Item 1. +Business +Available Information +This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website ( www.patenergy.com ) as soon as reasonably practicable after we electronically file such material with, or furnish it to, +the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at +2 +Table of Contents +1-800-SEC-0330. The SEC maintains an internet site ( www.sec.gov ) that contains reports, proxy and information statements and other information regarding issuers that file electronically +with the SEC. +Overview +We own and operate one of the largest fleets of land-based drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia, Ohio and western Canada. +As of December 31, 2011, we had a drilling fleet that consisted of 328 marketable land-based drilling rigs. A drilling rig includes +the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without +significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components. +We provide +pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. +We also own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas +working interests are located primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. We sold our drilling and completion fluids services business on January 20, 2010. +On October 1, 2010, we acquired the assets and operations of a pressure pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on +January 27, 2011. The results of our drilling and completion fluids services business and our electric wireline business are presented as discontinued operations in this Report. +Industry Segments +Our revenues, operating profits and identifiable assets +are primarily attributable to three industry segments: +• +contract drilling services, +• +pressure pumping services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2011 and 2010. In 2009, our pressure pumping services and oil and natural gas exploration and production segments had operating profits and our +contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments. +Contract Drilling Operations +General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2011, we had 328 marketable land-based drilling rigs based in +the following regions: +• +64 in west Texas and southeastern New Mexico, +• +73 in north central and east Texas, northern Louisiana and Mississippi, +• +48 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and North Dakota), +• +62 in south Texas and southern Louisiana, +3 +Table of Contents +• +27 in the Texas panhandle, Oklahoma and Arkansas, +• +34 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,250 feet to 25,000 feet. Of these drilling rigs, 145 are electric rigs and 183 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. We also have a substantial inventory of drill pipe and drilling rig components, which +may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs. +Drilling rigs are +typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each +year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent over $1.8 billion during the last three years on capital expenditures to (1) build new land drilling +rigs and (2) modify, upgrade and maintain our drilling fleet. During fiscal years 2011, 2010 and 2009, we spent approximately $785 million, $656 million and $395 million, respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected +for a particular job. +Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts +and other related rig equipment, fuel and other materials and qualified personnel. Some of these have been in short supply from time to time. +Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term +basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently one to three years) and provide for the use of +the drilling rig to drill multiple wells. During 2011, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 22 days. +Our 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. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for the payment of an early termination payment to us in the event that +the contract is terminated by the customer. We believe that our drilling contracts generally provide for identification rights and obligations that are customary for the markets in which we conduct those operations; however, each drilling contract +contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions or other factors. +Our drilling 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 job 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. +Under daywork contracts, we provide the drilling rig and crew to the customer. +The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are +interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. Except for two wells drilled under footage contracts in 2009, all of +the wells we drilled in 2011, 2010 and 2009 were under daywork contracts. +4 +Table of Contents +Under footage contracts, we contract to drill a well to a certain depth under specified +conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the +agreed-upon depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires +more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor typically assumes certain risks +associated with loss of the well from fire, blowouts and other risks. We drilled two wells under footage contracts in 2009, and we did not drill any wells under footage contracts in 2011 or 2010. +Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey +arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, +casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed-upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey contracts in the past three years. +Contract Drilling Activity +— Information regarding our contract drilling activity for the last three years follows: +Year Ended December 31, +2011 +2010 +2009 +Average rigs operating per day(1) +216 +168 +91 +Number of rigs operated during the year +250 +220 +243 +Number of wells drilled during the year +3,529 +2,919 +1,539 +Number of operating days +78,758 +61,244 +33,394 +(1) +A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. +Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to +match the needs of our customers. While conventional wells remain an important source of natural gas and oil, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for natural gas and +oil in North America. +5 +Table of Contents +To address our customers’ needs for drilling wells in the newer horizontal shale and +other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling fleet. We have delivered new APEX™ rigs to the market and have made performance and safety improvements to existing high +capacity rigs. APEX 1500™ rigs are 1,500 horsepower electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other highly automated pipe handling equipment. APEX 1000™ rigs are +1,000 horsepower electric rigs with advanced technology equipment similar to the APEX 1500™ rigs, but with a more compact design to fit on smaller locations. APEX Walking™ rigs are designed to efficiently drill multiple wells from a single +pad, by “walking” between the wellbores without requiring time to lower the mast and lay down the drill pipe. As of December 31, 2011 our drilling fleet was comprised of the following: +Number of Rigs +Classification +U.S. +Canada +Total +APEX 1500™ rigs +38 +— +38 +APEX 1000™ rigs (including eight with walking systems) +13 +— +13 +APEX Walking™ rigs +40 +— +40 +Other electric rigs +46 +8 +54 +Total electric rigs +137 +8 +145 +Mechanical rigs +171 +12 +183 +Total +308 +20 +328 +We estimate the depth capacity with respect to our marketable rigs as of December 31, 2011 to be as +follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,250 to 7,999 +— +3 +3 +8,000 to 11,999 +31 +9 +40 +12,000 to 15,999 +175 +8 +183 +16,000 to 25,000 +102 +— +102 +Total +308 +20 +328 +At December 31, 2011, we owned and operated 326 trucks and 403 trailers used to rig down, transport +and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations in periods of high drilling rig utilization. +We perform repair and overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, +Colorado, Pennsylvania and western Canada. +Pressure Pumping Operations +General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the +Appalachian Basin (Northeast Region). Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require +well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation +services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing. +Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered +into for a specified +6 +Table of Contents +period of time and may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other +items. We believe that our pressure pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each pressure pumping contract contains the actual +terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions or other factors. +Equipment — We have pressure pumping equipment used in providing hydraulic and nitrogen fracturing services as well as +nitrogen, cementing and acid pumping services, with a total of approximately 631,000 hydraulic horsepower as of December 31, 2011. Pressure pumping equipment at December 31, 2011 included: +Quintiplex +Fracturing +Equipment +Triplex +Fracturing +Equipment +Other +Pumping +Equipment +Total +Southwest Region: +Number of units +107 +22 +21 +150 +Approximate hydraulic horsepower +250,750 +37,750 +20,270 +308,770 +Northeast Region: +Number of units +76 +69 +109 +254 +Approximate hydraulic horsepower +171,000 +90,000 +61,300 +322,300 +Combined: +Number of units +183 +91 +130 +404 +Approximate hydraulic horsepower +421,750 +127,750 +81,570 +631,070 +Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, +manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite. +Materials — Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, +from time to time. We purchase these materials from various suppliers. These purchases are made in the spot market or pursuant to other arrangements, that do not cover all of our required supply and that sometimes require us to purchase the supply +or pay liquidated damages if we do not purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for +continued provision of any particular material or should one of our suppliers fail to deliver or timely deliver our materials. +Oil and +Natural Gas Interests +We own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil +and natural gas working interests are located primarily in producing regions of Texas and New Mexico. Our oil and natural gas assets constituted less than 1% of our consolidated assets as of December 31, 2011. +Customers +The customers +of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2011, no single customer accounted for 10% or more +of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand. The price for our services is a key +competitive factor, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications +7 +Table of Contents +of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for land drilling and pressure +pumping services will continue to be highly competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, other waste materials and acids, +• +use of underground storage tanks, +• +use of underground injection wells, and +• +hydraulic fracturing and related activities. +To date, applicable environmental laws and regulations in the United States and Canada have not required the expenditure of significant resources outside the ordinary course of business. We do not +anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any +new requirements could become material, and we could incur liability in any instance of noncompliance. +Our business is +generally affected by political developments and by federal, state, foreign, and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase costs relating to drilling and production, and otherwise have an adverse effect on our operations. Federal, state, foreign and local environmental laws and regulations currently apply +to our operations and may become more stringent in the future. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a federal, state, foreign or local governmental authority, could have a material adverse +effect on our business, financial condition and results of operation. +We believe 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 operated by us or our predecessors, which may have resulted, or may result, in soil +and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under federal, state, foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator. +Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, +but the discussion does not cover all environmental laws and regulations that govern our operations. +In the United States, 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. +8 +Table of Contents +The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and +comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production +wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of +materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages +recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages. +Our activities +include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential impacts of hydraulic fracturing on +groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such +efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers. See “Item 1A. Risk +Factors — Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Result in Operational Delays.” +In Canada, a variety of Canadian federal, provincial and municipal laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, +use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and +other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and +approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. +Our operations are also subject to federal, state, foreign and local laws, rules and regulations for the control of air emissions, +including the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining +operating permits and approvals for air emissions. For example, in July 2011, the U.S. Environmental Protection Agency (“EPA”) published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for +Hazardous Air Pollutants (“NESHAP”) that would impose, among other things, new standards for completions of hydraulically fractured natural gas wells. For more information, please refer to our discussion under “Item 1A. Risk Factors +— We Are Subject to Compliance with +9 +Table of Contents +Stringent Environmental Laws and Regulations That May Expose Us to Significant Costs and Liabilities, and Future Regulations May Be More Stringent.” +We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) +emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of +Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate +actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. See “Item 1A. Risk Factors — Legislation and Regulation of Greenhouse +Gases Could Adversely Affect Our Business.” +Risks and Insurance +Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, +blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property. Our operations could also cause significant +environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, +our drilling and pressure pumping contracts typically contain contractual rights to indemnity from our customer for, among other things, reservoir and certain pollution damage. Our contractual right to indemnification, however, may be unenforceable +or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their contractual indemnification obligations to us due to financial, legal or other reasons. +Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial +condition, cash flows and results of operations. +We maintain insurance coverage of types and amounts that we believe to be +customary for our businesses, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other +risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any +insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our +drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. +For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self insured retention on our general liability insurance coverage. We +self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. If a significant accident or other event occurs and is not +fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our +operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be +available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such +10 +Table of Contents +insurance prohibitive or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims +for insurance coverage. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors — Our Operations +Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May +Not Fully Protect Us.” +Employees +We had approximately 8,200 full-time employees at December 31, 2011. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee +relations to be satisfactory. None of our employees are represented by a union. +Seasonality +Seasonality has not significantly affected our overall operations, however the winter weather in the Appalachian Basin has recently +resulted in slower activity for our pressure pumping operations. In addition, our drilling operations in Canada and, to a lesser extent, our pressure pumping operations in the Appalachian Basin, are subject to slow periods of activity during the +annual Spring thaw. +Raw Materials and Subcontractors +We use many suppliers of raw materials and services. Although these materials and services have historically been available, 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. +Item 1A. +Risk Factors. +You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us +or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the +other information set forth in this Report, including our consolidated financial statements and the related notes. +Global Economic Conditions May Adversely Affect Our Operating Results. +Beginning in late 2008 and continuing through 2009, there was a substantial deterioration in the global economic environment. As part of +this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our +services. Furthermore, these factors resulted in certain of our customers experiencing an inability to pay suppliers, including us. Although the significant deterioration in the global economic environment appeared to stabilize to some degree during +2010 and 2011, there is no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. A return of the conditions causing a deterioration in the global economic environment could have a material +adverse effect on our business, financial condition, cash flows and results of operations. +11 +Table of Contents +We Are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and +Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results. +We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in North America. If these expenditures decline, our +business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as: +• +the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage, +• +the prices, and expectations about future prices, of oil and natural gas, +• +the supply of and demand for drilling and pressure pumping equipment, +• +the cost of exploring for, developing, producing and delivering oil and natural gas, +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate +drilling and hydraulic fracturing activities, and +• +merger and divestiture activity among oil and natural gas producers. +In particular, our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and +expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as: +• +market supply and demand, +• +international military, political and economic conditions, +• +the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets, +• +technical advances affecting energy consumption, and +• +the price and availability of alternative fuels. +All of these factors are beyond our control. During the second quarter of 2008, the quarterly average market price of natural gas (Henry Hub spot price as reported by the Energy Information +Administration) was $11.74 per Mcf and the quarterly average market price of oil (WTI spot price as reported by the Energy Information Administration) was $123.95 per barrel. In the last half of 2008, commodity prices rapidly declined and averaged +$6.60 per Mcf for natural gas and $58.35 per barrel for oil in the fourth quarter of 2008. In 2009, the price of natural gas declined further and averaged $4.06 per Mcf for the year. Oil prices remained depressed during 2009 as well and averaged +$61.65 per barrel for the year. These declines in the market price of natural gas and oil resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low +throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributed to increased development of unconventional oil and natural gas reservoirs and an improvement in +the price of oil which averaged $79.40 per barrel in 2010. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year. Natural gas prices decreased in 2011 to an average of $4.00 per Mcf. +The 2011 decrease in natural gas prices was most significant in the fourth quarter where the average price dropped to $3.32 per Mcf and this decrease has continued into 2012 where natural gas prices fell below $3.00 per Mcf in January. The increase +in drilling activity in oil rich basins has absorbed the decrease in demand for natural gas drilling activities in 2011 and our rig count increased in both 2010 and 2011. Our average number of rigs operating remains well below the number of our +available rigs. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of decreased drilling activity and excess capacity, our average number of rigs +operating has declined from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would +likely result in lower demand for our drilling rigs and pressure +12 +Table of Contents +pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and +natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services. +A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and Excess Pressure Pumping Equipment May Adversely +Affect Our Utilization and Profit Margins. +The North American oil and natural gas services industry has experienced +downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have +had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. +In addition, +unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to +successfully compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new technology drilling rigs. +Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has +resulted in excess capacity of conventional drilling rigs. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services and we believe there has been, and we expect there to +continue to be, a significant increase in the construction of new pressure pumping equipment. The addition of new pressure pumping equipment, as well as any general decline in demand for pressure pumping services, could result in there being +substantially more pressure pumping equipment available than necessary to meet demand. If this were to occur, providers of pressure pumping services will have difficulty sustaining profit margins and may sustain losses during downturn periods. We +cannot predict the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses. +Shortages of Drill Pipe, Replacement Parts, Other Equipment, Supplies and Materials Adversely Affect Our Operating Results. +During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages +of drill pipe, replacement parts, other equipment, supplies and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and +require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, +among other reasons: +• +weather issues, whether short-term such as a hurricane, or long-term such as a drought, and +• +a shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of +vendors to other customers or third parties. +These price increases, delays in delivery and interruptions in +supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our drilling rigs and pressure +pumping equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations. +13 +Table of Contents +Fixed Term Contracts May in Certain Instances Be Terminated Without an Early +Termination Payment. +Fixed term drilling contracts customarily provide for termination at the election of the +customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, in certain limited circumstances, for example, destruction of a drilling rig that is not +replaced within a specified period of time, our bankruptcy, or a sustained breach of our contract obligations, no early termination payment may be paid to us. Additionally, during depressed market conditions or otherwise, customers may seek to +terminate, renegotiate or fail to honor their contractual obligations. The failure to receive an early termination payment under a number of our fixed-term contracts could have a material adverse effect on our business, financial condition, cash +flows and results of operations. +The Oil Service Business Segments in Which We Operate Are Highly Competitive with +Excess Capacity, which Adversely Affects Our Operating Results. +Our land drilling and pressure pumping businesses are +highly competitive. At 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 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. As a result of competition, our utilization may decrease and/or we may be unable to maintain or increase prices for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of +operations. +Labor Shortages and Rising Labor Costs Adversely Affect Our Operating Results. +During periods of increasing demand for contract drilling and pressure pumping services, the industry experiences shortages of qualified +personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs and pressure pumping equipment is adversely affected, which negatively impacts both our operations and +profitability. Operationally, it is more difficult to hire qualified personnel, which adversely affects our ability to mobilize inactive rigs and pressure pumping equipment in response to the increased demand for such services. Additionally, wage +rates for drilling and pressure pumping personnel are likely to increase during periods of increasing demand, resulting in higher operating costs. +The Loss of Large Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations. +In 2011, we received approximately 41 percent of our consolidated operating revenues from our ten largest customers (including their +affiliates). Although no single customer accounted for more than seven percent of our consolidated operating revenue in 2011, the loss of one or more of our larger customers could have a material adverse effect on our business, financial condition, +cash flows and results of operations. +Growth Through the Building of New Rigs and Pressure Pumping Equipment and Rig +and Other Acquisitions Are Not Assured. +We have increased our drilling rig fleet and pressure pumping horsepower in +the past through mergers, acquisitions and new construction. The land drilling and pressure pumping industries have experienced significant consolidation, and there can be no assurance that acquisition opportunities will be available in the future. +We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, contract drillers may continue +to build new, high technology rigs and providers of pressure pumping services may continue to build new, high horsepower equipment. +14 +Table of Contents +There can be no assurance that we will: +• +have sufficient capital resources to complete additional acquisitions or build new rigs or pressure pumping equipment, +• +successfully integrate additional drilling rigs, pressure pumping equipment or other assets, +• +effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping equipment, +• +successfully deploy idle, stacked or additional rigs and pressure pumping equipment, +• +maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment, or +• +successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition or the building of +new drilling rigs and pressure pumping equipment. +We may incur substantial indebtedness to finance future +acquisitions, build new drilling rigs or build new pressure pumping equipment and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a +significant burden on our results of operations and financial condition, and the issuance of additional equity could be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources. +Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could +Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us. +Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, +blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property. Our operations could also cause significant +environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, +our drilling and pressure pumping contracts typically contain contractual rights to indemnity from our customers for, among other things, reservoir and certain pollution damage. Our contractual right to indemnification, however, may be unenforceable +or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet their contractual indemnification obligations to us due to financial, legal or other reasons. +Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. +We maintain +insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we +maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance, workers’ compensation and insurance for +other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we +carry insurance to cover physical damage to, or loss of, our drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk +through increased deductibles on certain insurance policies. For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self +insured retention on our general liability insurance coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir +damage. +15 +Table of Contents +Our insurance will not in all situations provide sufficient funds to protect us from all +liabilities that could result from our operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no +assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive or +that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for which we are not fully +insured or indemnified could materially affect our business, financial condition, cash flows and results of operations. +If a +significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition, cash flows and results of +operations. +We Are Dependent Upon our Subsidiaries to Meet our Obligations Under our Long Term Debt +We have borrowings outstanding under a term loan and revolving credit facility as well as our senior notes. These obligations are +guaranteed by each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends paid to us by our subsidiaries. If our subsidiaries do not +generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal payment obligations. +Variable Rate Indebtedness Subjects Us to Interest Rate Risk, Which Could Cause Our Debt Service Obligations to Increase +Significantly. +We have in place a committed senior unsecured credit facility that includes a revolving credit facility +and a term loan facility. Interest is paid on the outstanding principal amount of borrowings under the credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the +margin on base rate loans ranges from 1.75% to 2.75%, based on our debt to capitalization ratio. At December 31, 2011, the margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of December 31, 2011, we had $110 +million outstanding under our revolving credit facility at a weighted average interest rate of 4.05% and $92.5 million outstanding under our term credit facility at an interest rate of 3.25%. A one percent increase in the interest rate on the +borrowings outstanding under our revolving and term credit facilities as of December 31, 2011 would increase our annual cash interest expense by approximately $2.0 million. Interest rates could rise for various reasons in the future and +increase our total interest expense, depending upon the amounts borrowed. +New Technologies May Cause Our Drilling and +Pressure Pumping Processes and Equipment to Become Less Competitive, Resulting in an Adverse Effect on our Financial Condition and Results of Operations. +Changes in technology or improvements in competitors’ processes and equipment could make our processes and equipment less competitive or require significant capital expenditures to keep our processes +and equipment competitive. Any such changes in technology could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Environmental Laws and Regulations, Including Violations Thereof Could Materially Adversely Affect Our Operating Results. +All of our operations and facilities are subject to numerous federal, state, foreign and local environmental laws, rules and regulations, +including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance +with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States and Canada impose a +variety of requirements 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 and pressure pumping equipment, we may be deemed to +be a responsible party under these laws and regulations. +16 +Table of Contents +Changes in environmental laws and regulations occur frequently and such laws and regulations +tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase compliance costs for us and our customers and have a material adverse effect on our operations or financial position. For +example, in July 2011, the EPA issued proposed rules under the NSPS and NESHAP programs that would, among other things, impose new standards for flowback operations during completions at new, hydraulically fractured or re-fractured natural gas +wells. These proposed rules may require the implementation of new operating standards which may impact our business. If these or other initiatives result in an increase in regulation, it could increase costs to us and our customers or reduce demand +for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Result in Operational Delays. +Members of the U.S. Congress and the EPA are reviewing more stringent regulation of hydraulic fracturing, a technology employed by our +pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the EPA and the U.S. Congress are studying whether there is any link between +hydraulic fracturing activities and soil or ground water contamination. As part of their respective studies, the House Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our company, for +information on their hydraulic fracturing practices. We have responded to each of the inquiries. In addition, legislation has been proposed in the U.S. Congress to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used +by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing +process are impairing ground water or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result +in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Certain states where we operate, including Texas, have adopted or are considering similar +disclosure legislation. For example, Colorado, North Dakota, Montana, Texas, Louisiana, and Wyoming have adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various +degrees of chemical disclosure. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the +process of drafting guidance documents related to this newly asserted regulatory authority. Additional regulation could increase the costs of conducting our business and could materially reduce our business opportunities and revenues if our +customers decrease their levels of activity in response to such regulation. +There are also certain governmental reviews either +underway or being proposed that focus on environmental aspects of hydraulic fracturing practices, including the White House Council on Environmental Quality and a committee of the United States House of Representatives. Furthermore, a number of +federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review a variety of environmental issues associated with hydraulic fracturing. Also, the U.S. Department of the Interior is considering +disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing or proposed studies, depending on their course, and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing +under the Safe Drinking Water Act or other regulatory mechanism. +Legislation and Regulation of Greenhouse Gases Could +Adversely Affect our Business +We are aware of the increasing focus of local, state, national and international +regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the +Canadian provinces of Alberta and British Columbia. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHG present a danger to public health and the environment +17 +Table of Contents +because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting +and implementing regulations to restrict emissions of GHGs under existing provisions of the Federal Clean Air Act, including one regulation that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of +GHGs from certain large sources. In addition, the EPA published rules requiring reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, which has been amended to include certain onshore and +offshore oil and natural gas production facilities. In addition, almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG +cap and trade programs. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, +where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Because our business depends on the level of activity in the oil and natural gas industry, +existing or future laws or regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and +natural gas. +Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and +Thereby Affect the Related Purchase Price. +We are a Delaware corporation subject to the Delaware General Corporation +Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors 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. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws +impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential +acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market +prices pursuant to any such transactions. +Item 1B. +Unresolved Staff Comments. +None. +Item 2. +Properties +Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment. We own substantially all of the equipment used in our businesses. +Our corporate headquarters is in leased office space and is located at 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at +that address is (281) 765-7100. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000 square feet of office and storage space. +Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout +our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada. +Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our +areas of operations including Texas, Pennsylvania, Ohio, West Virginia, Kentucky, Tennessee and Colorado. +Oil and Natural +Gas Working Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico. +18 +Table of Contents +We own our administrative offices 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. +We incorporate by reference in response to this item the information set forth in Item 1 of this Report and the +information set forth in Note 4 of the Notes to Consolidated Financial Statements included in Item 8 of this Report. +Item 3. +Legal Proceedings. +We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a +material adverse effect on our results of operations, cash flows or financial condition. +Item 4. +Mine Safety Disclosure. +Not applicable. +19 +Table of Contents +PART II +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +(a) +Market Information +Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol +“PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated: +High +Low +2010: +First quarter +$ +18.67 +$ +13.19 +Second quarter +16.15 +11.85 +Third quarter +17.42 +12.52 +Fourth quarter +22.67 +16.59 +2011: +First quarter +$ +29.49 +$ +19.60 +Second quarter +32.42 +26.38 +Third quarter +34.09 +17.22 +Fourth quarter +23.90 +15.06 +(b) +Holders +As of +February 9, 2012, there were approximately 1,500 holders of record of our common stock. +(c) +Dividends +We paid +cash dividends during the years ended December 31, 2010 and 2011 as follows: +Per Share +Total +(in thousands) +2010: +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +2011: +Paid on March 30, 2011 +$ +0.05 +$ +7,708 +Paid on June 30, 2011 +0.05 +7,772 +Paid on September 30, 2011 +0.05 +7,777 +Paid on December 30, 2011 +0.05 +7,788 +Total cash dividends +$ +0.20 +$ +31,045 +On February 1, 2012, our Board of Directors approved a cash dividend on our common stock in the +amount of $0.05 per share to be paid on March 30, 2012 to holders of record as of March 15, 2012. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon +business conditions, results of operations, financial condition, terms of our credit facilities and other factors. +20 +Table of Contents +(d) +Securities Authorized for Issuance Under Equity Compensation Plans +Equity compensation plan information as of December 31, 2011 follows: +Equity Compensation Plan Information +Plan Category +Number of +Securities to +be Issued upon +Exercise of +Outstanding +Options, +Warrants and +Rights +Weighted- +Average +Exercise +Price of +Outstanding +Options, +Warrants and +Rights +Number of +Securities +Remaining Available +for Future Issuance +under +Equity +Compensation +Plans +(Excluding +Securities Reflected +in +Column(a)) +(a) +(b) +(c) +Equity compensation plans approved by security holders(1) +7,045,495 +$ +20.76 +4,399,951 +Equity compensation plans not approved by security holders(2) +35,800 +$ +14.64 +— +Total +7,081,295 +$ +20.73 +4,399,951 +(1) +The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended (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, officers 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. In addition to the 2005 Plan, this Plan +category also includes the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (the “1997 Plan”). 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. Options granted under the 1997 Plan typically vested over three or five years as dictated by the Compensation Committee. +All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant. +(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 officers and directors. No incentive stock options could be awarded under the 2001 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. +21 +Table of Contents +(e) +Unregistered Sales of Equity Securities and Use of Proceeds +The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2011. +Period Covered +Total +Number of +Shares +Purchased +Average Price +Paid +per +Share +Total Number of +Shares +(or Units) +Purchased as Part +of Publicly +Announced Plans +or Programs +Approximate Dollar +Value of +Shares +That May Yet Be +Purchased Under the +Plans or +Programs (in +thousands)(1) +October 1-31, 2011(2) +4,709 +$ +19.74 +664 +$ +112,868 +November 1-30, 2011(2) +51 +$ +19.11 +— +$ +112,868 +December 1-31, 2011(2) +51 +$ +20.25 +— +$ +112,868 +Total +4,811 +$ +19.74 +664 +$ +112,868 +(1) +On August 1, 2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or +privately negotiated transactions. +(2) +We withheld 4,045 shares in October, 51 shares in November and 51 shares in December from employees with respect to their tax withholding obligations upon the vesting +of restricted shares. The price paid was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive +Plan and not pursuant to the stock buyback program. +22 +Table of Contents +(e) +Performance Graph +The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2006 through +December 31, 2011, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of +Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Drilling Company, Bronco Drilling Company, Inc. and Precision Drilling Corp. Bronco Drilling Company, Inc. was acquired by another entity in 2011. All of the companies in our peer +group are providers of land-based drilling services. Nabors Industries, Ltd. also is a provider of pressure pumping services. BJ Services Company and Superior Well Services, Inc. were members of our peer group for 2010, but they were acquired by +other entities in 2010 and are therefore not members of our peer group for 2011. The graph assumes investment of $100 on December 31, 2006 and reinvestment of all dividends. +Fiscal Year Ended December 31, +Company/Index +2006 +($) +2007 +($) +2008 +($) +2009 +($) +2010 +($) +2011 +($) +Patterson-UTI Energy, Inc. +100.00 +85.70 +52.15 +70.66 +100.39 +93.86 +Peer Group Index +100.00 +100.07 +49.76 +79.64 +93.03 +90.69 +S&P 500 Stock Index +100.00 +105.49 +66.46 +84.05 +96.71 +98.76 +Oilfield Service Index +100.00 +151.52 +61.40 +99.57 +126.39 +113.02 +S&P MidCap Index +100.00 +107.97 +68.84 +94.57 +119.77 +117.68 +The foregoing graph is based on historical data and is not necessarily indicative of future performance. +This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act. +23 +Table of Contents +Item 6. +Selected Financial Data. +Our selected consolidated financial data as of December 31, 2011, 2010, 2009, 2008 and 2007, and for each of the five years in the period ended December 31, 2011 should be read in conjunction +with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Due to the sale +of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January 2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations in all +periods presented. +Years Ended December 31, +2011 +2010 +2009 +2008 +2007 +(In thousands, except per share amounts) +Statement of Operations Data: +Operating revenues: +Contract drilling +$ +1,669,581 +$ +1,081,898 +$ +599,287 +$ +1,804,026 +$ +1,741,647 +Pressure pumping +845,803 +350,608 +161,441 +217,494 +202,812 +Oil and natural gas +50,559 +30,425 +21,218 +42,360 +41,637 +Total +2,565,943 +1,462,931 +781,946 +2,063,880 +1,986,096 +Operating costs and expenses: +Contract drilling +972,778 +655,678 +357,742 +1,038,327 +963,150 +Pressure pumping +561,398 +235,100 +124,100 +147,377 +117,250 +Oil and natural gas +9,615 +7,020 +7,341 +12,793 +10,864 +Depreciation, depletion, amortization and impairment +437,279 +333,493 +289,847 +275,990 +246,346 +Selling, general and administrative +64,271 +53,042 +43,935 +43,273 +42,688 +Net (gain) loss on asset disposals +(4,999 +) +(22,812 +) +3,385 +(4,163 +) +(16,432 +) +Provision for bad debts +— +(2,000 +) +3,810 +4,350 +2,875 +Embezzlement recoveries +— +— +— +— +(43,955 +) +Acquisition-related expenses +— +2,485 +— +— +— +Total +2,040,342 +1,262,006 +830,160 +1,517,947 +1,322,786 +Operating income (loss) +525,601 +200,925 +(48,214 +) +545,933 +663,310 +Other income (expense) +(14,883 +) +(10,171 +) +(3,341 +) +1,425 +527 +Income (loss) from continuing operations before income taxes +510,718 +190,754 +(51,555 +) +547,358 +663,837 +Income tax expense (benefit) +187,938 +72,856 +(17,595 +) +193,490 +229,350 +Income (loss) from continuing operations +$ +322,780 +$ +117,898 +$ +(33,960 +) +$ +353,868 +$ +434,487 +Income (loss) from continuing operations per common share: +Basic +$ +2.08 +$ +0.77 +$ +(0.22 +) +$ +2.29 +$ +2.78 +Diluted +$ +2.06 +$ +0.76 +$ +(0.22 +) +$ +2.27 +$ +2.75 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.20 +$ +0.60 +$ +0.44 +Weighted average number of common shares outstanding: +Basic +153,871 +152,772 +152,069 +153,379 +154,755 +Diluted +155,304 +153,276 +152,069 +154,358 +156,612 +Balance Sheet Data: +Total assets +$ +4,221,901 +$ +3,423,031 +$ +2,662,152 +$ +2,712,817 +$ +2,465,199 +Borrowings under line of credit +110,000 +— +— +— +50,000 +Other long term debt +382,500 +392,500 +— +— +— +Stockholders’ equity +2,516,631 +2,187,607 +2,081,700 +2,126,942 +1,896,030 +Working capital +346,238 +241,445 +263,511 +337,615 +226,209 +24 +Table of Contents +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +Management Overview — We are a leading provider of 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 pressure pumping services. In addition to the aforementioned services, we also invest, on a non-operating working interest basis, in oil and natural gas +properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators. Due to our exit +from the drilling and completion fluids business in January 2010, we have presented the results of that business as discontinued operations in this Report. We acquired an electric wireline business on October 1, 2010 and sold the business on +January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this Report. +As of December 31, 2011, we had a drilling fleet that consisted of 328 marketable land-based drilling rigs. Although there continued to be uncertainty with respect to the global economic environment +and fluctuation of commodity prices, activity in our drilling business continued to increase during 2011. In the fourth quarter of 2011, our average number of rigs operating increased to 232 including 220 in the United States and 12 in Canada, as +compared to an average of 194 drilling rigs operating, including 182 rigs in the United States and 12 rigs in Canada during the same period in 2010. +While conventional wells remain an important source of natural gas and oil, this increased activity results, in part, from our addressing our customers’ needs for drilling wells in the newer +horizontal shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of December 31, 2011, we have completed 91 new APEX™ rigs +and made performance and safety improvements to existing high capacity rigs. We expect to complete an additional 30 new APEX™ rigs in 2012. In connection with the newer horizontal shale and other unconventional resource plays, we see a +continued need for equipment to perform service intensive fracturing jobs. As of December 31, 2011, we have also added over 467,000 hydraulic horsepower to our pressure pumping fleet since the end of 2009, and we had a total of approximately +631,000 hydraulic horsepower in our pressure pumping fleet at the end of 2011. Though the beginning of 2012 has seen unusually low natural gas prices, high oil prices are expected to increase drilling and pressure pumping activity in the oil and +liquids rich areas. +We maintain a backlog of commitments for contract drilling revenues under long-term contracts, which we +define as contracts with a fixed term of one year or more. Our backlog as of December 31, 2011 was approximately $1.6 billion. We expect approximately $898 million of our backlog to be realized in 2012. We calculate our backlog by multiplying +the day rate under our long-term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does +it include potential reductions in rates during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our long-term drilling +contracts are subject to termination by the customer on short notice and provide for the payment of an early termination payment to us in the event that the contract is terminated by the customer. See Item 1A. Risk Factors — Fixed Term +Contracts May in Certain Instances be Terminated Without an Early Termination Payment. +For the three years ended +December 31, 2011, our operating revenues from continuing operations consisted of the following (dollars in thousands): +2011 +2010 +2009 +Contract drilling +$ +1,669,581 +65 +% +$ +1,081,898 +74 +% +$ +599,287 +76 +% +Pressure pumping +845,803 +33 +350,608 +24 +161,441 +21 +Oil and natural gas +50,559 +2 +30,425 +2 +21,218 +3 +$ +2,565,943 +100 +% +$ +1,462,931 +100 +% +$ +781,946 +100 +% +25 +Table of Contents +Generally, the profitability of our business is impacted most by two primary factors in our +contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2011, our average number of rigs operating was 216 compared to 168 in 2010 and 91 in 2009. Our average revenue per operating day was +$21,200 in 2011 compared to $17,670 in 2010 and $17,950 in 2009. Additionally, our pressure pumping segment experienced an increase in large multi-stage fracturing jobs in 2011 compared to 2010 and 2009. This increase includes the contribution of a +pressure pumping business we acquired on October 1, 2010, which significantly expanded our pressure pumping operations into new markets in the fourth quarter of 2010. We had consolidated net income of $322 million for 2011 compared to $117 +million for 2010. The increase in consolidated net income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating and an increase in the average revenue per operating day as well as greater +activity, pricing and size of our pressure pumping business. +Our revenues, profitability and cash flows are highly dependent +upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in +periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing for our services. After reaching a peak in June 2008, there was a significant extended decline in oil and +natural gas prices and a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our +customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average number of rigs operating from a high of 283 in October 2008 to a low of 60 in June +2009. Our monthly average number of rigs operating has subsequently increased from the mid-year low of 60 in 2009 to 233 in December 2011 and our profitability has improved. +We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial +condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report. +Critical Accounting +Policies +In addition to established accounting policies, our consolidated financial statements are impacted by certain +estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition, the use of estimates and oil and natural gas properties,. +Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, +are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not +change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our long-lived assets, +including property and equipment, for impairment whenever events or changes in circumstances (“triggering events”) indicate that the carrying values of certain assets may not be recovered over their estimated remaining useful lives. In +connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods +of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of +the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in +the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured based on discounted cash +flows. +26 +Table of Contents +On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the +condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer horizontal wells using +high capacity rigs). In connection with our ongoing planning process, we evaluated our then-current fleet of marketable drilling rigs in 2011, 2010 and 2009 and identified 53, four and 23 rigs, during each of those years respectively, that we +determined were impaired and would no longer be marketed as rigs based on our assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as well as our assessment of future demand and the +suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs were transferred to other rigs or to our yards to be +used as spare equipment. The fair value of the remaining components of these rigs was estimated to be zero as there was no future cash flow expected and the associated net book value of $15.7 million in 2011, $4.2 million in 2010 and $10.5 million +in 2009 was expensed in our consolidated statements of operations as an impairment charge. +In late 2008, oil and natural gas +prices decreased significantly, and we experienced a significant decrease in the number of our rigs operating. A continued decrease in the operating levels in our contract drilling segment through the first half of 2009 was deemed by us to be a +triggering event that required us to perform an assessment with respect to impairment of long-lived assets, including property and equipment, in our contract drilling segment in 2009. With respect to these long-lived assets, we estimated future cash +flows over the expected life of the long-lived assets, which were comprised primarily of drilling rigs and related equipment (excluding the rigs which had been removed from our marketable fleet), and determined that, on an undiscounted basis, +expected cash flows exceeded the carrying value of the long-lived assets at that time. Based on this assessment, no further impairment was indicated in 2009. In light of the favorable trends in rig utilization and revenue per operating day +experienced by us and our peers in 2010 and 2011, we concluded that no triggering events occurred in 2010 or 2011 with respect to our contract drilling segment as a whole which would indicate that the carrying amounts of long-lived assets in that +segment may not be recoverable (excluding the rigs which had been removed from our marketable fleet). We concluded that no triggering event occurred with respect to our pressure pumping segment in 2011, 2010 or 2009. Impairment considerations +related to our oil and natural gas segment are discussed below. +Goodwill — Goodwill is considered to have an +indefinite useful economic life and is not amortized. We assess impairment of our goodwill annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its +carrying value. Goodwill impairment testing is performed at the level of our reporting units. Our reporting units have been determined to be the same as our operating segments. We currently have goodwill in our contract drilling and pressure pumping +operating segments. +In connection with our annual impairment assessment of goodwill as of December 31, 2010, we first +compared the fair value of the reporting units with their carrying value. In completing this first step of our analysis, we estimated our enterprise value based on our market capitalization as determined by reference to the closing price of our +common stock during the fifteen days before and after year end. We allocated this enterprise value to our reporting units and determined that the fair values of our reporting units were in excess of their carrying value. The fair value of our +reporting units as of December 31, 2010 exceeded the carrying value in all cases such that no impairment was indicated. If the carrying value had exceeded the fair value, we would have measured any impairment of goodwill in that reporting unit +by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair values. Any excess unallocated fair value would equal the implied fair value of goodwill, and if that amount was below the +carrying value of goodwill, an impairment charge would have been recognized. +In September 2011, the Financial Accounting +Standards Board (“FASB”) issued an accounting standards update which provides entities with the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is +more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is more likely than not that the fair value of a reporting unit is +greater than its carrying amount, then +27 +Table of Contents +performing the two-step impairment test described above is unnecessary. The provisions of this accounting standards update are effective for goodwill impairment tests performed for fiscal years +beginning after December 15, 2011, however, early adoption is permitted. We elected to adopt the provisions of the new goodwill impairment accounting standard issued in September 2011 in connection with our annual impairment assessment of +goodwill as of December 31, 2011 and determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their carrying amount and further testing was not +necessary. +In making our determination, we considered the continued demand experienced during 2011 for our services in the +contract drilling and pressure pumping businesses. We also considered the level of commodity prices for crude oil and natural gas, which influence our overall level of business activity in these operating segments. Additionally, current year +operating results and forecasted operating results for the coming year were also taken into account. Our overall market capitalization and the large amount of calculated excess of the fair values of our reporting units over their carrying values and +lack of significant changes in the key assumptions from our 2010 quantitative Step 1 assessment of goodwill were also considered. We have undertaken extensive efforts in the past several years to upgrade our fleet of equipment and believe that we +are well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical wells that may result from recent +decreases in natural gas prices. In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, and such impairment could be material. +Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services +are performed. 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 the 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 total revenues. We recognize as +revenue reimbursements received from third parties for out-of-pocket expenses and account for those out-of-pocket expenses as direct costs. Except for two wells drilled under footage contacts in 2009, all of the wells we drilled in 2011, 2010 and +2009 were drilled under daywork contracts. +Use of estimates — The preparation of financial statements in +conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets +and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation, depletion and amortization, +• +fair values of assets acquired and liabilities assumed in acquisitions, +• +goodwill and long-lived asset impairments, and +• +reserves for self-insured levels of insurance coverage. +Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of +accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are +charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to +28 +Table of Contents +wells-in-progress until the outcome of the drilling is known. We review wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic +viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider the well costs 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 for +each respective field. +We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, +such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future commodity prices over the lives +of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference +between net book value and discounted cash flow. The discounted cash flow estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field. We review unproved oil and natural gas +properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be +impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $3.0 million, $792,000 and $3.7 million for the years ended December 31, 2011, 2010 and +2009, respectively, and is included in depreciation, depletion, amortization and impairment in the consolidated statements of operations. +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. +Liquidity and Capital Resources +As of December 31, 2011, we had working capital of $346 million, including cash and cash equivalents of $23.9 million, compared to working capital of $241 million and cash and cash equivalents of +$27.6 million at December 31, 2010. +During 2011, our sources of cash flow included: +• +$869 million from operating activities, +• +$110 million in net borrowings under our revolving credit facility, +• +$25.5 million in proceeds from the disposal of our electric wireline business, +• +$23.2 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and +• +$22.5 million in proceeds from the disposal of property and equipment. +During 2011, we used $31.0 million to pay dividends on our common stock, $4.3 million to repurchase shares of our common stock, $6.3 +million to repay long-term debt and $1.0 billion: +• +to build new drilling rigs and pressure pumping equipment, +• +to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment, +• +to acquire and procure equipment and facilities to support our drilling and pressure pumping operations, and +• +to fund investments in oil and natural gas properties on a working interest basis. +29 +Table of Contents +We paid cash dividends during the year ended December 31, 2011 as follows: +Per Share +Total +(in thousands) +Paid on March 30, 2011 +$ +0.05 +$ +7,708 +Paid on June 30, 2011 +0.05 +7,772 +Paid on September 30, 2011 +0.05 +7,777 +Paid on December 30, 2011 +0.05 +7,788 +Total cash dividends +$ +0.20 +$ +31,045 +On February 1, 2011, our Board of Directors approved a cash dividend on our common stock in the +amount of $0.05 per share to be paid on March 30, 2012 to holders of record as of March 15, 2012. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon +business conditions, results of operations, financial condition, terms of our credit facilities and other factors. +On +August 1, 2007, our Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the year ended December 31, 2011, we +purchased 8,689 shares of our common stock under this program at a cost of approximately $255,000. As of December 31, 2011, we are authorized to purchase approximately $113 million of our outstanding common stock under this program. +On August 19, 2010, we entered into a Credit Agreement (the “Credit Agreement”). The Credit Agreement is a committed senior +unsecured credit facility that includes a revolving credit facility and a term loan facility. +The revolving credit facility +permits aggregate borrowings of up to $400 million and contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million. Subject to customary conditions, we may request that the +lenders’ aggregate commitments with respect to the revolving credit facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the revolving credit facility is August 19, 2013. +The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility is +payable in quarterly principal installments commencing November 19, 2010. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for +each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the next subsequent three quarterly installments, with the remainder becoming due at maturity. The maturity date for the term loan facility is +August 19, 2014. +Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base +rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon our debt to capitalization ratio. As of December 31, 2011, +the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn +under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to capitalization ratio and was 0.50% as of December 31, 2011. +The Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The +Credit Agreement also requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45% at any time. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of +(a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the +interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization +(“EBITDA”) of the four prior fiscal +30 +Table of Contents +quarters to interest charges for the same period. We were in compliance with these financial covenants as of December 31, 2011. We do not expect that the restrictions and covenants will +impair, in any material respect, our ability to operate or react to opportunities that might arise. +As of December 31, +2011, we had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 3.25% and had $110 million principal amount outstanding under the revolving credit facility at a weighted-average interest rate of 4.05%. We +had $40.6 million in letters of credit outstanding at December 31, 2011, and as a result, we had available borrowing capacity under the revolving credit facility of approximately $249 million at that date. +On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior +Notes due October 5, 2020 (the “Notes”) in a private placement. +The Notes bear interest at a rate of +4.97% per annum. We pay interest on the Notes on April 5 and October 5 of each year. The Notes will mature on October 5, 2020. The Notes are prepayable at our option, in whole or in part, provided that in the case of a partial +prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the +prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. We must offer to prepay the Notes upon the occurrence of any change of control. In addition, we must offer to prepay the Notes upon the occurrence of +certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is 100% of the principal amount thereof, plus accrued and unpaid +interest thereon to the prepayment date. +The note purchase agreement requires compliance with two financial covenants. We must +not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness +plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to +1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges for the same period. We were in compliance with these financial covenants as of December 31, +2011. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. +Events of default under the note purchase agreement and the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross +default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under +the note purchase agreement occurs and is continuing, then holders of a majority in principal amount of the Notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on +any Note, then until such defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and payable. +We believe that our liquidity as of December 31, 2011, which includes approximately $346 million in working capital and approximately $249 million available under our $400 million revolving credit +facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. +If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or +additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all. +Commitments and Contingencies — As of December 31, 2011, we maintained letters of credit in the aggregate amount of $40.6 million for the benefit of various insurance companies as +collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of +December 31, 2011, no amounts had been drawn under the letters of credit. +31 +Table of Contents +As of December 31, 2011, we had commitments to purchase approximately $352 million of +major equipment for our drilling and pressure pumping businesses. +Our pressure pumping business has entered into agreements to +purchase minimum quantities of proppants from certain vendors. These agreements expire in 2013 and 2016. As of December 31, 2011, the remaining obligation under these agreements is approximately $42.5 million, of which materials with a total +purchase price of approximately $13.5 million are expected to be delivered during 2012. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the +respective vendor for any shortfall. +In November 2011, our pressure pumping business entered into an agreement with a proppant +vendor to advance, on a non-revolving basis, up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and other assets and bears interest at an +annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2011, advances of +approximately $2.9 million had been made under this agreement and no significant repayments had been made. +Trading and +Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and +money market accounts. +Contractual Obligations +The following table presents information with respect to our contractual obligations as of December 31, 2011 (dollars in thousands): +Payments due by period +Total +Less than 1 +year +1-3 years +3-5 years +More than 5 +years +Borrowings under revolving credit facility(1) +$ +110,000 +$ +— +$ +110,000 +$ +— +$ +— +Interest on revolving credit facility(2) +7,276 +4,456 +2,820 +— +— +Borrowings under term loan(3) +92,500 +10,000 +82,500 +— +— +Interest on term loan(4) +6,351 +2,855 +3,496 +— +— +Series A Senior Notes(5) +300,000 +— +— +— +300,000 +Interest on Series A Senior Notes(6) +130,636 +14,910 +29,820 +29,820 +56,086 +Commitments to purchase equipment(7) +351,738 +351,738 +— +— +— +Commitments to purchase inventory(8) +42,466 +13,461 +17,617 +11,388 +— +$ +1,040,967 +$ +397,420 +$ +246,253 +$ +41,208 +$ +356,086 +(1) +Any borrowings that are drawn on our revolving credit facility would be due at maturity August 19, 2013. Amount reflected in table is borrowings outstanding as of +December 31, 2011. +(2) +Interest is calculated at 4.05%, which is the weighted average interest rate on outstanding borrowings under the revolving credit facility as of December 31, 2011. +(3) +Represents repayments of borrowing under the term loan portion of the Credit Agreement. The term loan matures on August 19, 2014. +32 +Table of Contents +(4) +Interest to be paid on term loan using 3.25% rate in effect as of December 31, 2011. +(5) +Principal repayment of the Series A Senior Notes is required at maturity on October 5, 2020. +(6) +Interest to be paid on the Series A Senior Notes using 4.97% coupon rate. +(7) +Represents commitments to purchase major equipment to be delivered in 2012 based on expected delivery dates. +(8) +Represents commitments to purchase proppants for our pressure pumping business. +Off-Balance Sheet Arrangements +We had no off-balance sheet arrangements at +December 31, 2011. +Results of Operations +Comparison of the years ended December 31, 2011 and 2010 +The following tables summarize operations by business segment for the years ended December 31, 2011 and 2010: +Year Ended December 31, +Contract Drilling +2011 +2010 +% Change +(Dollars in thousands) +Revenues +$ +1,669,581 +$ +1,081,898 +54.3 +% +Direct operating costs +$ +972,778 +$ +655,678 +48.4 +% +Selling, general and administrative +$ +6,408 +$ +5,279 +21.4 +% +Depreciation and impairment +$ +344,312 +$ +280,458 +22.8 +% +Operating income +$ +346,083 +$ +140,483 +146.4 +% +Operating days +78,758 +61,244 +28.6 +% +Average revenue per operating day +$ +21.20 +$ +17.67 +20.0 +% +Average direct operating costs per operating day +$ +12.35 +$ +10.71 +15.3 +% +Average rigs operating +216 +168 +28.6 +% +Capital expenditures +$ +784,686 +$ +655,550 +19.7 +% +The demand for our contract drilling services is impacted by the market price of natural gas and oil. The +reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal +quarters and full year in 2011 and 2010 follows: +1 st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2010: +Average natural gas price per Mcf(1) +$ +5.30 +$ +4.45 +$ +4.41 +$ +3.91 +$ +4.52 +Average oil price per Bbl(2) +$ +78.64 +$ +77.79 +$ +76.05 +$ +85.10 +$ +79.40 +2011: +Average natural gas price per Mcf(1) +$ +4.18 +$ +4.37 +$ +4.12 +$ +3.32 +$ +4.00 +Average oil price per Bbl(2) +$ +93.50 +$ +102.22 +$ +89.72 +$ +93.99 +$ +94.86 +(1) +The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +33 +Table of Contents +Revenues and direct operating costs increased in 2011 compared to 2010 as a result of an +increase in the number of operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2011 primarily due to increases in contractual dayrates. Average direct operating +costs per operating day increased in 2011 due primarily to higher repairs, maintenance and labor costs. The increase in operating days was largely due to increased demand resulting from higher oil prices. Selling, general and administrative expenses +increased in 2011 primarily as a result of increased personnel costs to support increased activity levels. Capital expenditures were incurred in 2011 and 2010 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire +additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures. Depreciation +and impairment expense included approximately $15.7 million in 2011 and approximately $4.2 million in 2010 of impairment charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed 53 rigs from our +marketable fleet in 2011 and removed four rigs from our marketable fleet in 2010. +Year Ended December 31, +Pressure Pumping +2011 +2010 +% Change +(Dollars in thousands) +Revenues +$ +845,803 +$ +350,608 +141.2 +% +Direct operating costs +$ +561,398 +$ +235,100 +138.8 +% +Selling, general and administrative +$ +17,686 +$ +12,590 +40.5 +% +Depreciation and amortization +$ +73,279 +$ +40,724 +79.9 +% +Operating income +$ +193,440 +$ +62,194 +211.0 +% +Fracturing jobs +1,531 +1,527 +0.3 +% +Other jobs +7,010 +6,047 +15.9 +% +Total jobs +8,541 +7,574 +12.8 +% +Average revenue per fracturing job +$ +467.85 +$ +180.21 +159.6 +% +Average revenue per other job +$ +18.48 +$ +12.47 +48.2 +% +Average revenue per total job +$ +99.03 +$ +46.29 +113.9 +% +Average direct operating costs per total job +$ +65.73 +$ +31.04 +111.8 +% +Capital expenditures +$ +198,061 +$ +51,064 +287.9 +% +Contributing to the increases in revenues, direct operating costs, selling, general and administrative +expenses and depreciation and amortization was our acquisition of a pressure pumping business on October 1, 2010, which significantly expanded the size of our fleet of pressure pumping equipment and the markets in which we provide pressure +pumping services. This acquisition was accounted for as a business combination and the results of operations of the acquired business are included in our pressure pumping segment results from the date of acquisition. The acquired business +contributed revenue of $456 million and operating income of $106 million to our operating results during the year ended December 31, 2011 compared to revenue of $84.7 million and operating income of $22.8 million during the year ended +December 31, 2010. +Our customers have increased their activities in the development of unconventional reservoirs +resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional equipment through construction and acquisition to meet this demand and expand our area of operations. As a result, we have experienced an +increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per fracturing job increased as a result of this increase in the number of larger multi-stage fracturing +jobs in 2011 as compared to 2010, as well as increased pricing. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per total job increased +primarily as a result of the increase in the number of larger multi-stage fracturing jobs. Selling, general and administrative expenses in 2011 include $6.4 million associated with the acquired business compared to $1.5 million for 2010. Significant +capital expenditures have been incurred in recent years to add capacity in our pressure pumping segment. Depreciation and amortization expense +34 +Table of Contents +in 2011 includes $4.1 million in amortization of intangible assets compared to $1.0 million in amortization of intangible assets for 2010. The remaining increase in depreciation in 2011 compared +to 2010 was a result of our recent capital expenditures and our October 1, 2010 acquisition. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2011 +2010 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +44,495 +$ +24,722 +80.0 +% +Revenues — Natural gas and liquids +$ +6,064 +$ +5,703 +6.3 +% +Revenues — Total +$ +50,559 +$ +30,425 +66.2 +% +Direct operating costs +$ +9,615 +$ +7,020 +37.0 +% +Depletion and impairment +$ +16,962 +$ +10,950 +54.9 +% +Operating income +$ +23,982 +$ +12,455 +92.5 +% +Capital expenditures +$ +22,884 +$ +23,067 +(0.8 +)% +Total revenues increased as a result of increased production and higher prices for oil and liquids. Oil +production increased primarily due to the addition of new wells. Depletion and impairment expense in 2011 includes approximately $3.0 million of oil and natural gas property impairments compared to approximately $792,000 of oil and natural gas +property impairments in 2010. Depletion expense increased approximately $3.8 million in 2011 compared to 2010 primarily due to increased oil production. +Year Ended December 31, +Corporate and Other +2011 +2010 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +40,177 +$ +35,173 +14.2 +% +Depreciation +$ +2,726 +$ +1,361 +100.3 +% +Net gain on asset disposals +$ +(4,999 +) +$ +(22,812 +) +(78.1 +)% +Provision for bad debts +$ +— +$ +(2,000 +) +(100.0 +)% +Acquisition-related expenses +$ +— +$ +2,485 +(100.0 +)% +Interest income +$ +187 +$ +1,674 +(88.8 +)% +Interest expense +$ +15,652 +$ +12,772 +22.5 +% +Other income +$ +582 +$ +927 +(37.2 +)% +Capital expenditures +$ +5,947 +$ +8,409 +(29.3 +)% +Selling, general and administrative expense increased in 2011 primarily as a result of increased personnel +costs. Gains on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on disposal of assets in 2011 is primarily related to +the sale of scrap metal. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than the depths that we generally target for certain of the oil and natural gas +properties in which we have working interests. The negative provision for bad debts in 2010 is the result of collections of certain accounts that had previously been reserved, as well as reductions in our reserve for specific accounts due to +improved industry conditions. Acquisition-related expenses in 2010 were incurred in connection with the acquisition of pressure pumping and electric wireline businesses during the fourth quarter of 2010. These expenses included certain legal and +other professional fees directly related to the transaction, fees incurred in connection with the title transfers of the acquired equipment and transition costs related to information technology. Interest income in 2010 included the collection of +interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense increased in 2011 primarily due to interest charges on the 4.97% Senior Notes that were issued in October +2010, the term loan that was entered into in August 2010 and interest on borrowings under our revolving credit facility. Capital expenditures decreased in 2010 due to less activity with respect to the implementation of a new enterprise resource +planning system in 2011 compared to 2010. +35 +Table of Contents +Year Ended December 31, +Discontinued Operations: +2011 +2010 +% Change +(Dollars in thousands) +Electric wireline revenue +$ +1,104 +$ +5,712 +(80.7 +)% +Electric wireline direct operating costs +$ +1,831 +$ +4,962 +(63.1 +)% +Drilling and completion fluids revenue +$ +— +$ +3,737 +(100.0 +)% +Drilling and completion fluids direct operating costs +$ +— +$ +3,307 +(100.0 +)% +Selling, general and administrative +$ +46 +$ +358 +(87.2 +)% +Depreciation +$ +— +$ +166 +(100.0 +)% +Impairment of assets held for sale +$ +— +$ +2,155 +(100.0 +)% +Income tax benefit +$ +(209 +) +$ +(543 +) +(61.5 +)% +Loss from discontinued operations, net of income taxes +$ +(367 +) +$ +(956 +) +(61.6 +)% +On January 27, 2011, we sold our electric wireline business, which had been acquired by us on +October 1, 2010. The results of operations of this business have been classified as a discontinued operation. On January 20, 2010, we sold our drilling and completion fluids services business, which had previously been presented as one of +our reportable operating segments. Due to our exit from this business, we have classified our drilling and completion fluids operating segment as a discontinued operation. Impairment of assets held for sale in 2010 reflects the transaction-related +costs recorded to reduce the carrying value of the assets sold to their net realizable value at December 31, 2010. +Comparison of the years ended December 31, 2010 and 2009 +The following tables summarize operations by business segment for the years ended December 31, 2010 and 2009: +Year Ended December 31, +Contract Drilling +2010 +2009 +% Change +(Dollars in thousands) +Revenues +$ +1,081,898 +$ +599,287 +80.5 +% +Direct operating costs +$ +655,678 +$ +357,742 +83.3 +% +Selling, general and administrative +$ +5,279 +$ +4,340 +21.6 +% +Depreciation and impairment +$ +280,458 +$ +248,424 +12.9 +% +Operating income (loss) +$ +140,483 +$ +(11,219 +) +N/M +Operating days +61,244 +33,394 +83.4 +% +Average revenue per operating day +$ +17.67 +$ +17.95 +(1.6 +)% +Average direct operating costs per operating day +$ +10.71 +$ +10.71 +0.0 +% +Average rigs operating +168 +91 +84.6 +% +Capital expenditures +$ +655,550 +$ +395,376 +65.8 +% +The demand for our contract drilling services is impacted by the market price of natural gas and oil. The +reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal +quarters and full year in 2010 and 2009 follows: +1 st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2009: +Average natural gas price per Mcf (1) +$ +4.71 +$ +3.82 +$ +3.26 +$ +4.46 +$ +4.06 +Average oil price per Bbl (2) +$ +42.91 +$ +59.44 +$ +68.20 +$ +76.06 +$ +61.65 +2010: +Average natural gas price per Mcf (1) +$ +5.30 +$ +4.45 +$ +4.41 +$ +3.91 +$ +4.52 +Average oil price per Bbl (2) +$ +78.64 +$ +77.79 +$ +76.05 +$ +85.10 +$ +79.40 +36 +Table of Contents +(1) +The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +Revenues and direct operating costs increased in 2010 compared to 2009 as a result of an increase in the number of operating days. The +increase in operating days was due to increased demand largely resulting from higher prices for natural gas and oil. Our average number of rigs operating during 2009 included an average of approximately six rigs operating under term contracts that +earned standby revenues of $22.3 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. We had no significant standby revenue associated with rigs operating under term contracts in 2010. We recognized +approximately $8.0 million of revenues during 2009 from the early termination of term contracts. We had no such revenue from the early termination of term contracts in 2010. Selling, general and administrative expenses increased in 2010 primarily as +a result of increased personnel costs to support increased activity levels. Capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as +top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures. Depreciation and impairment expense included +approximately $4.2 million in 2010 and approximately $10.5 million in 2009 of impairment charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed four rigs from our marketable fleet in 2010 and +removed 23 rigs from our marketable fleet in 2009. +Year Ended December 31, +Pressure Pumping +2010 +2009 +% Change +(Dollars in thousands) +Revenues +$ +350,608 +$ +161,441 +117.2 +% +Direct operating costs +$ +235,100 +$ +124,100 +89.4 +% +Selling, general and administrative +$ +12,590 +$ +8,735 +44.1 +% +Depreciation and amortization +$ +40,724 +$ +27,589 +47.6 +% +Operating income +$ +62,194 +$ +1,017 +N/M +Fracturing jobs +1,527 +1,579 +(3.3 +)% +Other jobs +6,047 +5,399 +12.0 +% +Total jobs +7,574 +6,978 +8.5 +% +Average revenue per fracturing job +$ +180.21 +$ +70.88 +154.2 +% +Average revenue per other job +$ +12.47 +$ +9.17 +36.0 +% +Average revenue per total job +$ +46.29 +$ +23.14 +100.0 +% +Average direct operating costs per total job +$ +31.04 +$ +17.78 +74.6 +% +Capital expenditures +$ +51,064 +$ +43,144 +18.4 +% +Contributing to the increases in revenues, direct operating costs, selling, general and administrative +expenses and depreciation and amortization was our acquisition of a pressure pumping business on October 1, 2010, which significantly expanded the size of our fleet of pressure pumping equipment and the markets in which we provide pressure +pumping services. This acquisition was accounted for as a business combination and the results of operations of the acquired business are included in our pressure pumping segment results from the date of acquisition. The acquired business +contributed revenue of $84.7 million and operating income of $22.8 million to our operating results during the year ended December 31, 2010. +Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. As a result, we have +experienced an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per fracturing job increased as a result of this increase in the number of larger +multi-stage fracturing jobs in 2010 as compared to 2009. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per total job increased primarily as +a result of the increase in the number of larger multi-stage fracturing jobs. Selling, general +37 +Table of Contents +and administrative expenses in 2010 include $1.5 million associated with the acquired business. The remaining increase in selling, general and administrative expenses is due to additional costs +necessary to support increased business activity in 2010. Significant capital expenditures have been incurred in recent years to add capacity in our pressure pumping segment. Depreciation and amortization expense in 2010 includes $1.0 million in +amortization of intangible assets and $4.7 million in depreciation of property and equipment associated with the acquired business. The remaining increase in depreciation in 2010 compared to 2009 is a result of our recent capital expenditures. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2010 +2009 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +24,722 +$ +16,135 +53.2 +% +Revenues — Natural gas and liquids +$ +5,703 +$ +5,083 +12.2 +% +Revenues — Total +$ +30,425 +$ +21,218 +43.4 +% +Direct operating costs +$ +7,020 +$ +7,341 +(4.4 +)% +Depletion and impairment +$ +10,950 +$ +12,927 +(15.3 +)% +Operating income +$ +12,455 +$ +950 +N/M +Capital expenditures +$ +23,067 +$ +7,341 +214.2 +% +Total revenues increased as a result of increased production and higher prices for oil and liquids and +higher prices for natural gas. Oil production increased primarily due to the addition of new wells. Natural gas production decreased primarily due to production declines on existing wells. Depletion and impairment expense in 2010 includes +approximately $792,000 of oil and natural gas property impairments compared to approximately $3.7 million of oil and natural gas property impairments in 2009. Depletion expense increased approximately $915,000 in 2010 compared to 2009 due to +increased oil production. Capital expenditures increased in 2010 as a result of greater drilling activity and increased costs per well. +Year Ended December 31, +Corporate and Other +2010 +2009 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +35,173 +$ +30,860 +14.0 +% +Depreciation +$ +1,361 +$ +907 +50.1 +% +Net (gain) loss on asset disposals +$ +(22,812 +) +$ +3,385 +N/M +Provision for bad debts +$ +(2,000 +) +$ +3,810 +N/M +Acquisition-related expenses +$ +2,485 +$ +— +N/M +Interest income +$ +1,674 +$ +381 +339.4 +% +Interest expense +$ +12,772 +$ +4,148 +207.9 +% +Other income +$ +927 +$ +426 +117.6 +% +Capital expenditures +$ +8,409 +$ +6,785 +23.9 +% +Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel +costs. The provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment at the time. Gains and losses on the disposal of assets are treated as part +of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and +develop zones deeper than depths that we generally target for certain of the oil and natural gas properties in which we have working interests. Losses on asset disposals in 2009 were primarily related to the disposal of contract drilling equipment. +The negative provision for bad debts in 2010 is the result of collections of certain accounts that had previously been reserved, as well as reductions in our reserve for specific accounts due to improved industry conditions. Acquisition-related +expenses in 2010 were incurred in connection with the acquisition of pressure pumping and electric wireline businesses during the fourth quarter of 2010. These expenses included certain legal and other professional fees directly related to the +transaction, fees incurred in connection with the title transfers of the acquired equipment and transition costs related to information technology. +38 +Table of Contents +Interest income increased due to the collection of interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense in +2010 includes $3.3 million due to the recognition of remaining deferred financing costs associated with a revolving credit facility that was replaced in August 2010, and $1.3 million due to the recognition of financing costs associated with a bridge +facility that expired unused on September 30, 2010. The remainder of the 2010 increase relates to interest charges and the amortization of debt issuance costs associated with the $100 million term loan entered into in August 2010 and the $300 +million Senior Notes issued in October 2010. Capital expenditures increased in 2010 due to the ongoing implementation of a new enterprise resource planning system. +Year Ended December 31, +Discontinued Operations: +2010 +2009 +% Change +(Dollars in thousands) +Electric wireline revenue +$ +5,712 +$ +— +N/M +Electric wireline direct operating costs +$ +4,962 +$ +— +N/M +Drilling and completion fluids revenue +$ +3,737 +$ +79,786 +(95.3 +)% +Drilling and completion fluids direct operating costs +$ +3,307 +$ +74,180 +(95.5 +)% +Selling, general and administrative +$ +358 +$ +7,192 +(95.0 +)% +Depreciation +$ +166 +$ +2,287 +(92.7 +)% +Impairment of assets held for sale +$ +2,155 +$ +1,900 +13.4 +% +Net gain on asset disposals/retirements +$ +— +$ +(125 +) +(100.0 +% +Other operating expense +$ +— +$ +890 +(100.0 +)% +Income tax benefit +$ +(543 +) +$ +(2,208 +) +(75.4 +)% +Loss from discontinued operations, net of income taxes +$ +(956 +) +$ +(4,330 +) +(77.9 +)% +On January 27, 2011, we sold our electric wireline business, which had been acquired by us on +October 1, 2010. The results of operations of this business have been classified as a discontinued operation and the assets held for sale at December 31, 2010 are presented at net realizable value in the consolidated balance sheet. On +January 20, 2010, we sold our drilling and completion fluids services business, which had previously been presented as one of our reportable operating segments. Due to our exit from this business, we have classified our drilling and completion +fluids operating segment as a discontinued operation. Impairment of assets held for sale in 2010 and 2009 reflects the transaction-related costs recorded to reduce the carrying value of the assets sold to their net realizable value at +December 31, 2010, and 2009. +Income Taxes +Year Ended December 31, +2011 +2010 +2009 +(Dollars in thousands) +Income (loss) from continuing operations before income tax +$ +510,718 +$ +190,754 +$ +(51,555 +) +Income tax expense (benefit) +187,938 +72,856 +(17,595 +) +Effective tax rate +36.8 +% +38.2 +% +34.1 +% +The effective tax rate is a result of a federal rate of 35.0% adjusted as follows: +2011 +2010 +2009 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +2.5 +1.1 +4.7 +Permanent differences +(0.1 +) +2.3 +(5.7 +) +Other, net +(0.6 +) +(0.2 +) +0.1 +Effective tax rate +36.8 +% +38.2 +% +34.1 +% +39 +Table of Contents +The Domestic Production Activities Deduction was enacted as part of the American Jobs +Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 6% in 2009 and 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent +differences for 2010 and 2009 reflect the recapture of a portion of this deduction due to the carryback of the net operating loss to prior years. This recapture resulted in a negative effective rate impact in 2009 due to our having a loss before +income taxes in that year. The permanent difference for 2011 does not include any impact related to the Domestic Production Activities Deduction as such deduction is limited to the amount of taxable income in any given year and there is a tax loss +in 2011. +We record deferred federal income taxes based primarily on the temporary differences between the book and tax bases +of our assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of +our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We recognized deferred tax expense of approximately $159 million in 2011, $147 million in 2010 and $101 million in 2009. +On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for federal +income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax +expense over the weighted average remaining useful life of the Canadian assets. +As a result of the above conversion, our +Canadian assets are no longer directly subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted +earnings in Canada, and intend to do so for the foreseeable future. As a result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $25.2 million as of +December 31, 2011. +Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition +Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about +future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as market supply and demand, international military, political and economic conditions, the ability of OPEC to +set and maintain production and price targets, technical advances affecting energy consumption and the price and availability of alternative fuels. All of these factors are beyond our control. During the second quarter of 2008, the quarterly average +market price of natural gas (Henry Hub spot price as reported by the United States Energy Information Administration) was $11.74 per Mcf and the quarterly average market price of oil (WTI spot price as reported by the Energy Information +Administration) was $123.95 per barrel. In the last half of 2008, commodity prices rapidly declined and averaged $6.60 per Mcf for natural gas and $58.35 per barrel for oil in the fourth quarter of 2008. In 2009, the price of natural gas declined +further and averaged $4.06 per Mcf for the year. These declines in the market price of natural gas and oil resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities +remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributed to increased development of unconventional oil and natural gas reservoirs and an +improvement in the price of oil which averaged $79.40 per barrel in 2010. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year. Natural gas prices decreased in 2011 to an average of +$4.00 per Mcf. The 2011 decrease in natural gas prices was most significant in the fourth quarter where the average price dropped to $3.32 per Mcf and this decrease has continued into 2012 where natural gas prices fell below $3.00 per Mcf in +January. The increase in drilling activity in oil rich basins has absorbed the decrease in demand for natural gas drilling activities in 2011 and our rig count increased in both 2010 and 2011. Our average number of rigs operating remains well below +the number of our available rigs. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of decreased drilling activity and excess capacity, our average +number of rigs operating has declined from historic highs. We expect oil and natural gas prices to +40 +Table of Contents +continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand +for our drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may +cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling and pressure pumping services. +Impact of Inflation +Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2011. We believe +that inflation will not have a significant near-term impact on our financial position. +Recently Issued Accounting Standards +In September 2011, the FASB issued an accounting standard update that simplifies how entities test goodwill for +impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary +to perform the two-step goodwill impairment test. Previous guidance required an entity to test goodwill for impairment, on at least an annual basis, by comparing the fair value of a reporting unit with its carrying amount. If the fair value of a +reporting unit is less than its carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the amendments in this update, an entity is not required to calculate the fair value of a +reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. This update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after +December 15, 2011. Early adoption is permitted if an entity’s financial statements for the most recent annual or interim period have not yet been issued. We elected to early adopt this accounting standards update as of December 31, +2011 as discussed further in Note 5 to the Consolidated Financial Statements included in Item 8 of this Report. +In June +2011, the FASB issued an accounting standard update that requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In +the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and +the total of comprehensive income. Historically, these components of other comprehensive income and total comprehensive income have been presented in the statement of changes in stockholders’ equity by many companies, including us. This +requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and will be effective for the Company in the quarter ending March 31, 2012. The adoption of this update will result in +the addition of a new consolidated statement of comprehensive income to our consolidated financial statements beginning with the quarter ending March 31, 2012. +In May 2011, the FASB issued an accounting standard update to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with United States +GAAP and International Financial Reporting Standards. The amendments in this update do not require additional fair value measurements, but provide additional guidance as to measuring fair value as well as certain additional disclosure requirements. +The requirements in this update are effective during interim and annual periods beginning after December 15, 2011 and will be effective for us in the quarter ending March 31, 2012. The adoption of this update will not have a material +impact on the disclosures included in our consolidated financial statements. +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk associated with any borrowings that we have under our term credit facility or our +revolving credit facility. Interest is paid on the outstanding principal amount of +41 +Table of Contents +borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the margin on base rate loans ranges from 1.75% to 2.75%, +based on our debt to capitalization ratio. At December 31, 2011, the margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of December 31, 2011, we had $110 million outstanding under our revolving credit facility +at a weighted average interest rate of 4.05% and $92.5 million outstanding under our term credit facility at an interest rate of 3.25%. The interest rate on the borrowing outstanding under our term credit facility is variable and adjusts at each +interest payment date based on our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowing outstanding under our revolving and term credit facilities as of December 31, 2011 would increase our annual +cash interest expense by approximately $2.0 million. +We conduct a portion of our business in Canadian dollars through our +Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings +of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition. +The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term +maturity of these items. +Item 8. +Financial Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated +Financial Statements, and are incorporated herein by this reference. +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 9A. +Controls and Procedures. +Disclosure Controls and Procedures: +Under the supervision and with the +participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in +Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2011, our disclosure controls and procedures +were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. +Management’s Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the +participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011, based on the Internal Control-Integrated Framework +issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2011. +The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers +LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this Report. +42 +Table of Contents +Changes in Internal Control over Financial Reporting: +There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have +materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +Item 9B. +Other Information +None. +43 +Table of Contents +PART III +The information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities +Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference. +Item 10. +Directors, Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive +officer, principal financial officer and principal accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from +this code on our website. +Item 11. +Executive Compensation. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +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. +44 +Table of Contents +PART IV +Item 15. +Exhibits and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial +Statements on page F-1 of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts is filed herewith on page S-1. +All other financial statement schedules have been omitted because they are not applicable or the information required therein is included +elsewhere in the financial statements or notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by reference herein. +2.1 +Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure +Pumping Services, LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +2.2 +Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +2.3 +Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +3.1 +Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 +and incorporated herein by reference). +3.2 +Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended +June 30, 2004 and incorporated herein by reference). +3.3 +Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +3.4 +Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated +herein by reference). +4.1 +Restated Certificate of Incorporation, as amended (See Exhibits 3.1, 3.2 and 3.3). +4.2 +Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). +10.1 +For additional material contracts, see Exhibit 4.2. +45 +Table of Contents +10.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company's Registration +Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* +10.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarterly +period ended June 30, 2003 and incorporated herein by reference).* +10.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q +for the quarterly period ended June 30, 2004 and incorporated herein by reference).* +10.5 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company's Current Report on Form 8-K, and incorporated herein by +reference).* +10.6 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated +herein by reference). +10.7 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +10.8 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.9 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.10 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q and +incorporated herein by reference).* +10.11 +Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time (filed February 19, 2010 +as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference).* +10.12 +Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).* +10.13 +Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).* +10.14 +Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John +E. Vollmer III (filed 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).* +46 +Table of Contents +10.15 +Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form +10-K, as amended, and incorporated herein by reference).* +10.16 +Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on September 24, 2007 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K, and incorporated herein by reference).* +10.17 +Employment Agreement, effective as of January 1, 2012, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb. *+ +10.18 +Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry +H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 as Exhibit 10.11 to the Company's Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10.19 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as +Exhibit 10.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI Energy, Inc. and Douglas J. Wall (filed September 4, 2007 as +Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* +10.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 +as Exhibit 10.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, +2004 as Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.23 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.24 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit +10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.25 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as +Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.26 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.27 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as +Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* +47 +Table of Contents +10.28 +Credit Agreement dated August 19, 2010, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer and lender and each +of the other letter of credit issuer and lender parties thereto (filed August 19, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +10.29 +Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.+ +23.1 +Consent of Independent Registered Public Accounting Firm.+ +31.1 +Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +31.2 +Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +32.1 +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of +2002.+ +101 +The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting +Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to Consolidated +Financial Statements.+ +* +Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. ++ +Filed herewith. +48 +Table of Contents +INDEX TO CONSOLIDATED FINA NCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of December 31, 2011 and 2010 +F-3 +Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and +2009 +F-4 +Consolidated Statements of Changes In Stockholders’ Equity for the years ended December +31, 2011, 2010 and 2009 +F-5 +Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and +2009 +F-6 +Notes to Consolidated Financial Statements +F-7 +Schedule II - Valuation and Qualifying Accounts +S-1 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders +of Patterson-UTI Energy, Inc.: +In our opinion, the +consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2011 and 2010, and +the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the +financial 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 financial statements. Also in our +opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of +Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial +statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was +maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant +estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk +that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the +circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company’s internal control over financial +reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A +company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the +assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures +of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of +the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control +over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree +of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 10, 2012 +F-2 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +December 31, +2011 +2010 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +23,946 +$ +27,612 +Accounts receivable, net of allowance for doubtful accounts of $4,887 and $5,114 at December 31, 2011 and 2010, +respectively +518,109 +337,167 +Federal and state income taxes receivable +— +75,062 +Inventory +31,306 +17,215 +Deferred tax assets, net +142,725 +26,815 +Assets held for sale +— +23,370 +Other +48,864 +50,169 +Total current assets +764,950 +557,410 +Property and equipment, net +3,167,266 +2,620,900 +Goodwill and intangible assets +175,573 +179,683 +Deposits on equipment purchases +99,543 +51,084 +Other +14,569 +13,954 +Total assets +$ +4,221,901 +$ +3,423,031 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +241,610 +$ +162,400 +Federal and state income taxes payable +2,473 +— +Accrued expenses +164,629 +147,315 +Current portion of long-term debt +10,000 +6,250 +Total current liabilities +418,712 +315,965 +Borrowings under revolving credit facility +110,000 +— +Other long-term debt +382,500 +392,500 +Deferred tax liabilities, net +786,632 +511,422 +Other +7,426 +15,537 +Total liabilities +1,705,270 +1,235,424 +Commitments and contingencies (see Note 9) +Stockholders’ equity: +Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares with 183,295,350 and 181,537,568 issued and 155,807,779 and +154,193,754 outstanding at December 31, 2011 and 2010, respectively +1,833 +1,815 +Additional paid-in capital +840,731 +796,641 +Retained earnings +2,279,367 +1,987,999 +Accumulated other comprehensive income +19,459 +21,597 +Treasury stock, at cost, 27,487,571 shares and 27,343,814 shares at December 31, 2011 and 2010, respectively +(624,759 +) +(620,445 +) +Total stockholders’ equity +2,516,631 +2,187,607 +Total liabilities and stockholders’ equity +$ +4,221,901 +$ +3,423,031 +The accompanying notes are an integral part of these consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +Year Ended December 31, +2011 +2010 +2009 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,669,581 +$ +1,081,898 +$ +599,287 +Pressure pumping +845,803 +350,608 +161,441 +Oil and natural gas +50,559 +30,425 +21,218 +Total operating revenues +2,565,943 +1,462,931 +781,946 +Operating costs and expenses: +Contract drilling +972,778 +655,678 +357,742 +Pressure pumping +561,398 +235,100 +124,100 +Oil and natural gas +9,615 +7,020 +7,341 +Depreciation, depletion, amortization and impairment +437,279 +333,493 +289,847 +Selling, general and administrative +64,271 +53,042 +43,935 +Net (gain) loss on asset disposals +(4,999 +) +(22,812 +) +3,385 +Provision for bad debts +— +(2,000 +) +3,810 +Acquisition-related expenses +— +2,485 +— +Total operating costs and expenses +2,040,342 +1,262,006 +830,160 +Operating income (loss) +525,601 +200,925 +(48,214 +) +Other income (expense): +Interest income +187 +1,674 +381 +Interest expense +(15,652 +) +(12,772 +) +(4,148 +) +Other +582 +927 +426 +Total other expense +(14,883 +) +(10,171 +) +(3,341 +) +Income (loss) from continuing operations before income taxes +510,718 +190,754 +(51,555 +) +Income tax expense (benefit): +Current +28,971 +(74,634 +) +(119,038 +) +Deferred +158,967 +147,490 +101,443 +Total income tax expense (benefit) +187,938 +72,856 +(17,595 +) +Income (loss) from continuing operations +322,780 +117,898 +(33,960 +) +Loss from discontinued operations, net of income taxes +(367 +) +(956 +) +(4,330 +) +Net income (loss) +$ +322,413 +$ +116,942 +$ +(38,290 +) +Basic income (loss) per common share: +Income (loss) from continuing operations +$ +2.08 +$ +0.77 +$ +(0.22 +) +Loss from discontinued operations, net of income taxes +$ +0.00 +$ +(0.01 +) +$ +(0.03 +) +Net income (loss) +$ +2.08 +$ +0.76 +$ +(0.25 +) +Diluted income (loss) per common share: +Income (loss) from continuing operations +$ +2.06 +$ +0.76 +$ +(0.22 +) +Loss from discontinued operations, net of income taxes +$ +0.00 +$ +(0.01 +) +$ +(0.03 +) +Net income (loss) +$ +2.06 +$ +0.76 +$ +(0.25 +) +Weighted average number of common shares outstanding: +Basic +153,871 +152,772 +152,069 +Diluted +155,304 +153,276 +152,069 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.20 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Common Stock +Additional +Paid-in +Capital +Retained +Earnings +Accumulated +Other +Comprehensive +Income +Treasury +Stock +Total +Number +of +Shares +Amount +(In thousands) +Balance, December 31, 2008 +180,192 +$ +1,801 +$ +765,512 +$ +1,970,824 +$ +5,774 +$ +(616,969 +) +$ +2,126,942 +Comprehensive income (loss): +Net loss +— +— +— +(38,290 +) +— +— +(38,290 +) +Foreign currency translation adjustment, (net of tax of $5,347) +— +— +— +— +9,222 +— +9,222 +Total comprehensive loss +— +— +— +(38,290 +) +9,222 +— +(29,068 +) +Issuance of restricted stock +604 +6 +(6 +) +— +— +— +— +Vesting of restricted stock units +6 +— +— +— +— +— +— +Forfeitures of restricted stock +(56 +) +— +— +— +— +— +— +Exercise of stock options +83 +1 +568 +— +— +— +569 +Stock-based compensation +— +— +18,565 +— +— +— +18,565 +Tax expense related to stock-based compensation +— +— +(3,004 +) +— +— +— +(3,004 +) +Payment of cash dividends +— +— +— +(30,681 +) +— +— +(30,681 +) +Purchase of treasury stock +— +— +— +— +— +(1,623 +) +(1,623 +) +Balance, December 31, 2009 +180,829 +1,808 +781,635 +1,901,853 +14,996 +(618,592 +) +2,081,700 +Comprehensive income: +Net Income +— +— +— +116,942 +— +— +116,942 +Foreign currency translation adjustment, (net of tax of $2,814) +— +— +— +— +6,601 +— +6,601 +Total comprehensive income +— +— +— +116,942 +6,601 +— +123,543 +Issuance of restricted stock +700 +7 +(7 +) +— +— +— +— +Vesting of restricted stock units +7 +— +— +— +— +— +— +Forfeitures of restricted stock +(59 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +61 +1 +524 +— +— +— +525 +Stock-based compensation +— +— +16,779 +— +— +— +16,779 +Tax expense related to stock-based compensation +— +— +(2,291 +) +— +— +— +(2,291 +) +Payment of cash dividends +— +— +— +(30,796 +) +— +— +(30,796 +) +Purchase of treasury stock +— +— +— +— +— +(1,853 +) +(1,853 +) +Balance, December 31, 2010 +181,538 +1,815 +796,641 +1,987,999 +21,597 +(620,445 +) +2,187,607 +Comprehensive income: +Net income +— +— +— +322,413 +— +— +322,413 +Foreign currency translation adjustment +— +— +— +— +(2,138 +) +— +(2,138 +) +Total comprehensive income +— +— +— +322,413 +(2,138 +) +— +320,275 +Issuance of restricted stock +782 +8 +(8 +) +— +— +— +— +Vesting of restricted stock units +10 +— +— +— +— +— +— +Forfeitures of restricted stock +(83 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +1,048 +11 +16,800 +— +— +— +16,811 +Stock-based compensation +— +— +20,904 +— +— +— +20,904 +Tax benefit related to stock-based compensation +— +— +6,393 +— +— +— +6,393 +Payment of cash dividends +— +— +— +(31,045 +) +— +— +(31,045 +) +Purchase of treasury stock +— +— +— +— +— +(4,314 +) +(4,314 +) +Balance, December 31, 2011 +183,295 +$ +1,833 +$ +840,731 +$ +2,279,367 +$ +19,459 +$ +(624,759 +) +$ +2,516,631 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +Year Ended December 31, +2011 +2010 +2009 +(In thousands) +Cash flows from operating activities: +Net income (loss) +$ +322,413 +$ +116,942 +$ +(38,290 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Depreciation, depletion, amortization and impairment +437,279 +333,493 +289,847 +Provision for bad debts +— +(2,000 +) +3,810 +Dry holes and abandonments +1,213 +519 +129 +Deferred income tax expense +158,967 +147,490 +101,443 +Stock-based compensation expense +20,904 +16,779 +18,214 +Net (gain) loss on asset disposals +(4,999 +) +(22,812 +) +3,385 +Tax expense related to stock-based compensation +— +(2,291 +) +(3,004 +) +Changes in operating assets and liabilities: +Accounts receivable +(183,165 +) +(178,444 +) +213,813 +Income taxes receivable/payable +77,618 +43,522 +(108,664 +) +Inventory and other assets +(13,491 +) +(8,772 +) +14,178 +Accounts payable +41,995 +49,576 +(52,673 +) +Accrued expenses +18,313 +18,072 +(21,178 +) +Other liabilities +(8,111 +) +3,234 +(92 +) +Net cash provided by (used in) operating activities of discontinued operations +(339 +) +10,390 +32,759 +Net cash provided by operating activities +868,597 +525,698 +453,677 +Cash flows from investing activities: +Acquisitions +— +(238,022 +) +— +Purchases of property and equipment +(1,011,578 +) +(738,090 +) +(452,646 +) +Proceeds from disposal of assets +22,495 +29,409 +3,359 +Net cash provided by (used in) investing activities of discontinued operations +25,500 +42,638 +(54 +) +Net cash used in investing activities +(963,583 +) +(904,065 +) +(449,341 +) +Cash flows from financing activities: +Purchases of treasury stock +(4,314 +) +(1,853 +) +(1,623 +) +Dividends paid +(31,045 +) +(30,796 +) +(30,681 +) +Tax benefit related to stock-based compensation +6,393 +— +— +Proceeds from long-term debt +— +400,000 +— +Repayment of long-term debt +(6,250 +) +(1,250 +) +— +Proceeds from borrowings under revolving credit facility +153,100 +200,000 +— +Repayment of borrowings under revolving credit facility +(43,100 +) +(200,000 +) +— +Debt issuance costs +— +(10,779 +) +(6,169 +) +Proceeds from exercise of stock options +16,811 +525 +569 +Net cash provided by (used in) financing activities +91,595 +355,847 +(37,904 +) +Effect of foreign exchange rate changes on cash +(275 +) +255 +2,222 +Net decrease in cash and cash equivalents +(3,666 +) +(22,265 +) +(31,346 +) +Cash and cash equivalents at beginning of year +27,612 +49,877 +81,223 +Cash and cash equivalents at end of year +$ +23,946 +$ +27,612 +$ +49,877 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest, net of capitalized interest of $8,415 in 2011, $2,288 in 2010 and $0 in 2009 +$ +(13,177 +) +$ +(2,220 +) +$ +1,804 +Income taxes +59,251 +115,666 +14,029 +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property and equipment +$ +37,838 +$ +29,188 +$ +(25,110 +) +Net (increase) decrease in deposits on equipment purchases +(48,459 +) +(50,170 +) +43,029 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. +Description of Business and Summary of Significant Accounting Policies +A description of the business and basis of presentation follows: +Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries (collectively referred to herein +as “Patterson-UTI” or the “Company”), provides onshore contract drilling services to major and independent oil and natural gas operators primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, +Wyoming, Montana, North Dakota, Pennsylvania, West Virginia, Ohio and western Canada. The Company provides pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. The Company also invests, on a +non-operating working interest basis, in oil and natural gas properties. +Basis of presentation — The consolidated +financial statements include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial +interests in any other entity which would require consolidation. +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 its functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of +stockholders’ equity. +A summary of the significant accounting policies follows: +Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in +the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the +reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. +Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed. +The Company follows the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to +be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and the risks therein, the Company follows 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 total revenues. The Company recognizes as +revenue reimbursements received from third parties for out-of-pocket expenses and accounts for those out-of-pocket expenses as direct costs. Except for two wells drilled under footage contacts in 2009, all of the wells the Company drilled in 2011, +2010 and 2009 were drilled under daywork contracts. +Accounts receivable — Trade accounts receivable are recorded +at the invoiced amount. 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 at least quarterly. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectability. Account balances, when determined to be +uncollectable, are charged against the allowance. +Inventories — Inventories consist primarily of sand and chemical +products to be used in conjunction with the Company’s pressure pumping activities. The inventories are stated at the lower of cost or market, determined by the first-in, first-out method. +F-7 +Table of Contents +Property and equipment — Property and equipment is carried at cost less +accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not change whenever equipment becomes idle. The estimated useful lives, in years, are shown below: +Useful Lives +Drilling rigs and other equipment +1.5-15 +Buildings +15-20 +Other +3-12 +Long-lived assets, including property and equipment, are evaluated for impairment when certain triggering +events or changes in circumstances indicate that the carrying values may not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of +accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are +charged to expense when such determination is made. 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 whether sufficient +progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, the +Company considers the well costs to be impaired and recognizes the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production +method, based on engineering estimates of proved oil and natural gas reserves for each respective field. +The Company reviews +its proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and +undiscounted cash flow estimates are prepared based on management’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a +field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and discounted cash flow. The discounted cash flow estimates used in measuring impairment are based on +management’s expectations of future commodity prices over the life of the respective field. The Company reviews unproved oil and natural gas properties quarterly to assess potential impairment. The Company’s impairment assessment is made +on a lease-by-lease basis and considers factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. +Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. The Company assesses +impairment of its goodwill at least annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value. +Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend +the life or improve existing property and equipment are capitalized. +Disposals — Upon disposition of property and +equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations. +Net income (loss) per common share — The Company provides a dual presentation of its net income (loss) per common share in its consolidated statements of operations: Basic net income (loss) +per common share (“Basic EPS”) and diluted net income (loss) per common share (“Diluted EPS”). +F-8 +Table of Contents +Basic EPS excludes dilution and is computed by first allocating earnings between common +stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period, excluding +non-vested shares of restricted stock. +Diluted EPS is based on the weighted average number of common shares outstanding plus +the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined using the treasury stock method. +The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive +effect of potential common shares other than non-vested shares of restricted stock. +The following table presents information +necessary to calculate income (loss) from continuing operations per share, loss from discontinued operations per share and net income (loss) per share for the years ended December 31, 2011, 2010 and 2009, as well as potentially dilutive +securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts): +2011 +2010 +2009 +BASIC EPS: +Income (loss) from continuing operations +$ +322,780 +$ +117,898 +$ +(33,960 +) +Adjust for (income) loss attributed to holders of non-vested restricted stock +(2,545 +) +(884 +) +313 +Income (loss) from continuing operations attributed to common stockholders +$ +320,235 +$ +117,014 +$ +(33,647 +) +Loss from discontinued operations, net +$ +(367 +) +$ +(956 +) +$ +(4,330 +) +Adjust for loss attributed to holders of non-vested restricted stock +3 +7 +38 +Loss from discontinued operations attributed to common stockholders +$ +(364 +) +$ +(949 +) +$ +(4,292 +) +Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock +153,871 +152,772 +152,069 +Basic income (loss) from continuing operations per common share +$ +2.08 +$ +0.77 +$ +(0.22 +) +Basic loss from discontinued operations per common share +$ +0.00 +$ +(0.01 +) +$ +(0.03 +) +Basic net income (loss) per common share +$ +2.08 +$ +0.76 +$ +(0.25 +) +DILUTED EPS: +Income (loss) from continuing operations attributed to common stockholders +$ +320,235 +$ +117,014 +$ +(33,647 +) +Add incremental earnings related to potential common shares +— +— +— +Adjusted income (loss) from continuing operations attributed to common stockholders +$ +320,235 +$ +117,014 +$ +(33,647 +) +Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock +153,871 +152,772 +152,069 +Add dilutive effect of potential common shares +1,433 +504 +— +Weighted average number of diluted common shares outstanding +155,304 +153,276 +152,069 +Diluted income (loss) from continuing operations per common share +$ +2.06 +$ +0.76 +$ +(0.22 +) +Diluted loss from discontinued operations per common share +$ +0.00 +$ +(0.01 +) +$ +(0.03 +) +Diluted net income (loss) per common share +$ +2.06 +$ +0.76 +$ +(0.25 +) +Potentially dilutive securities excluded as anti-dilutive +1,641 +4,164 +8,090 +F-9 +Table of Contents +Income taxes — The asset and liability method is used in accounting for income +taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing +assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or +settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is recorded to reduce the carrying +amounts of deferred tax assets unless it is more likely than not that such assets will be realized. The Company’s policy is to account for interest and penalties with respect to income taxes as operating expenses. +Stock-based compensation — The Company recognizes the cost of share-based payments under the fair-value-based method. Under +this method, compensation cost related to share-based payments is measured based on the estimated fair value of the awards at the date of grant, net of estimated forfeitures. This expense is recognized over the expected life of the awards (See Note +11). +Statement of cash flows — For purposes of reporting cash flows, cash and cash equivalents include cash on +deposit and money market funds. +Recently Issued Accounting Standards — In September 2011, the Financial Accounting +Standards Board (“FASB”) issued an accounting standard update that simplifies how entities test goodwill for impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that +the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. Previous guidance required an entity to test goodwill for impairment, on at +least an annual basis, by comparing the fair value of a reporting unit with its carrying amount. If the fair value of a reporting unit is less than its carrying amount, then the second step of the test must be performed to measure the amount of the +impairment loss, if any. Under the amendments in this update, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying +amount. This update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted if an entity’s financial statements for the most recent annual or +interim period have not yet been issued. The Company has elected to early adopt this accounting standard update as of December 31, 2011 as discussed further in Note 5. +In June 2011, the FASB issued an accounting standard update that requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive +income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive +income, the components of other comprehensive income, and the total of comprehensive income. Historically, these components of other comprehensive income and total comprehensive income have been presented in the statement of changes in +stockholders’ equity by many companies, including the Company. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and will be effective for the Company in the quarter +ending March 31, 2012. The adoption of this update will result in the addition of a new consolidated statement of comprehensive income to the Company’s consolidated financial statements beginning with the quarter ending March 31, +2012. +In May 2011, the FASB issued an accounting standard update to improve the comparability of fair value measurements +presented and disclosed in financial statements prepared in accordance with United States GAAP and International Financial Reporting Standards. The amendments in this update do not require additional fair value measurements, but provide additional +guidance as to measuring fair value as well as certain additional disclosure requirements. The requirements in this update are effective during interim and annual periods beginning after December 15, 2011 and will be effective for the Company +in the quarter ending March 31, 2012. The adoption of this update will not have a material impact on the Company’s disclosures included in its consolidated financial statements. +F-10 +Table of Contents +2. +Discontinued Operations +On January 20, 2010, the Company exited the drilling and completion fluids business, which had previously been +presented as one of the Company’s reportable operating segments. On that date, the Company’s wholly owned subsidiary, Ambar Lone Star Fluid Services LLC, completed the sale of substantially all of its assets, excluding billed accounts +receivable. The sales price was approximately $42.6 million. Upon the Company’s exit from the drilling and completion fluids business, the Company classified its drilling and completion fluids operating segment as a discontinued operation and +an impairment loss was recognized in 2009 to reduce the carrying value of the assets to be disposed of to fair value less estimated costs to sell and no significant gain or loss was recognized in connection with the sale in 2010. The results of +operations of this business have been reclassified and presented as results of discontinued operations for all periods presented in these consolidated financial statements. +On January 27, 2011, the stock of the Company’s electric wireline subsidiary, Universal Wireline, Inc., was sold in a cash transaction for $25.5 million. Except for inventory, the working +capital of Universal Wireline, Inc. was excluded from the sale and retained by a subsidiary of the Company. Universal Wireline, Inc. was formed in 2010 to acquire the electric wireline business of Key Energy Services, Inc., as discussed in Note 3. +The results of operations of this business have been presented as results of discontinued operations in these consolidated financial statements. As of December 31, 2010, the assets to be disposed of were classified as held for sale and are +presented separately within current assets under the caption “Assets held for sale” in the consolidated balance sheet. Upon being classified as held for sale, the assets to be disposed of were recorded at fair value less estimated costs to +sell resulting in a charge of $2.2 million. Due to the fact that the carrying value of the assets had been adjusted to net realizable value, no significant additional gain or loss was recognized in connection with the sale. +Summarized operating results from discontinued operations for the years ended December 31, 2011, 2010 and 2009 are shown below (in +thousands): +2011 +2010 +2009 +Drilling and completion fluids revenues +$ +— +$ +3,737 +$ +79,786 +Electric wireline revenues +1,104 +5,712 +— +Operating revenues from discontinued operations +$ +1,104 +$ +9,449 +$ +79,786 +Loss from discontinued operations before income taxes +$ +(576 +) +$ +(1,499 +) +$ +(6,538 +) +Income tax benefit +209 +543 +2,208 +Loss from discontinued operations +$ +(367 +) +$ +(956 +) +$ +(4,330 +) +The components of assets held for sale at December 31, 2010 are shown below (in thousands): +Assets held for sale: +Inventory +$ +756 +Property and equipment, net +24,769 +Reserve to reduce disposal group to fair value less costs to sell +(2,155 +) +Total assets held for sale +$ +23,370 +3. +Acquisitions +On October 1, 2010, two subsidiaries of the Company, Universal Pressure Pumping, Inc. and Universal Wireline, +Inc., completed the acquisition of certain assets from Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC relating to the businesses of providing pressure pumping services and +F-11 +Table of Contents +electric wireline services to participants in the oil and natural gas industry. This acquisition expanded the Company’s pressure pumping operations to additional markets primarily in Texas. +The aggregate purchase price was approximately $241 million and was allocated to the tangible and identifiable intangible assets acquired and liabilities assumed based on fair value. The tangible assets acquired include property and equipment, +inventories of sand and chemicals on hand and repair and maintenance supplies on hand. The identifiable intangible assets acquired include an agreement by the seller to not compete for a period of three years and the customer relationships in place +at the time of the acquisition. The liabilities assumed arose from pricing agreements in place with certain customers that had pricing below current market rates. A related deferred tax asset was recognized to reflect the temporary difference +associated with these below-market pricing arrangements. The excess of the purchase price over the fair values of the tangible assets, the identifiable intangible assets and deferred tax asset, net of the liabilities assumed, is recorded as goodwill +and was attributed to the pressure pumping business acquired. A summary of the purchase price allocation follows (in thousands): +Sand and chemical inventory +$ +6,848 +Supplies +312 +Property and equipment +154,359 +Non-compete agreement +1,400 +Customer relationships +25,500 +Deferred tax asset +8,514 +Goodwill +67,575 +Below-market pricing agreements +(23,200 +) +Total purchase price +$ +241,308 +In addition to the purchase price, acquisition-related expenses associated with this transaction of +approximately $2.5 million were incurred by the Company and are presented in the consolidated statement of operations under the caption “acquisition-related expenses” for the year ended December 31, 2010. These expenses include +certain legal and other professional fees directly related to the transaction, fees incurred in connection with title transfers of the acquired equipment and transition costs related to information technology. +As discussed in Note 2, the electric wireline business was classified as held for sale at December 31, 2010 and was subsequently sold +on January 27, 2011. The results of operations of the wireline business from the date of acquisition through December 31, 2010 included revenue of $5.7 million and a pre-tax operating loss of $1.5 million (including a charge of +approximately $2.2 million incurred to reduce the carrying value of the disposal group to its net realizable value) which is included in loss from discontinued operations for the year ended December 31, 2010. Results of operations of the +acquired pressure pumping business are included in the Company’s consolidated results of operations from the date of acquisition. Revenues of $84.7 million and income from operations of $22.8 million from the acquired pressure pumping business +are included in the consolidated statement of operations for the year ended December 31, 2010. +The following represents +pro-forma unaudited financial information for the years ended December 31, 2010 and 2009 as if the acquisition had been completed on January 1, 2009 (in thousands, except per share amounts): +2010 +2009 +(Unaudited) +Revenue +$ +1,660,635 +$ +905,168 +Income (loss) from continuing operations +$ +127,257 +$ +(46,807 +) +Net income (loss) +$ +126,301 +$ +(51,137 +) +Basic income (loss) from continuing operations per common share +$ +0.83 +$ +(0.33 +) +Basic net income (loss) per common share +$ +0.83 +$ +(0.36 +) +Diluted income (loss) from continuing operations per common share +$ +0.82 +$ +(0.33 +) +Diluted net income (loss) per common share +$ +0.82 +$ +(0.36 +) +F-12 +Table of Contents +4. +Property and Equipment +Property and equipment consisted of the following at December 31, 2011 and 2010 (in thousands): +2011 +2010 +Equipment +$ +4,730,925 +$ +3,972,891 +Oil and natural gas properties +131,812 +110,749 +Buildings +64,090 +61,425 +Land +11,467 +11,074 +4,938,294 +4,156,139 +Less accumulated depreciation and depletion +(1,771,028 +) +(1,535,239 +) +Property and equipment, net +$ +3,167,266 +$ +2,620,900 +Depreciation, depletion, amortization and impairment — The following table summarizes +depreciation, depletion, amortization and impairment expense related to property and equipment and intangible assets for 2011, 2010 and 2009 (in millions): +2011 +2010 +2009 +Depreciation and impairment expense +$ +419.2 +$ +322.3 +$ +280.6 +Amortization expense +4.1 +1.0 +— +Depletion expense +14.0 +10.2 +9.2 +Total +$ +437.3 +$ +333.5 +$ +289.8 +The Company evaluates the recoverability of its long-lived assets whenever events or changes in +circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). In light of adverse market conditions affecting the Company beginning in the fourth quarter of 2008 and continuing into 2009, including a +substantial decrease in the operating levels of its contract drilling business segment and a significant decline in oil and natural gas commodity prices, the Company determined that a triggering event had occurred and deemed it necessary to perform +an assessment with respect to impairment of long-lived assets, including property and equipment, within its contract drilling segment in 2009. In light of favorable trends in rig utilization and revenue per operating day experienced by the Company +and its peers in 2010 and 2011, management concluded that no triggering event had occurred in 2010 or 2011 with respect to its contract drilling segment as a whole (excluding the rigs which had been removed from the Company’s marketable fleet +as discussed below). The Company concluded that no triggering event occurred with respect to its pressure pumping segment in 2011, 2010 or 2009. With respect to the long-lived assets in the Company’s oil and natural gas exploration and +production segment, the Company assesses the recoverability of long-lived assets at the end of each quarter due to revisions in its oil and natural gas reserve estimates and expectations about future commodity prices. +Long-lived assets are evaluated for impairment at the lowest level for which identifiable cash flows can be separated from other +long-lived assets. The Company performs the first step of its impairment assessments by comparing the undiscounted cash flows for each long-lived asset or asset group to its respective carrying value. Based on the results of these impairment tests, +the carrying amounts of long-lived assets in the contract drilling and oil and natural gas segments were determined to be recoverable, except as described below. +The Company’s analysis indicated that the carrying amounts of certain oil and natural gas properties were not recoverable at various testing dates in 2011, 2010 and 2009. The Company’s estimates +of expected future net cash flows from impaired properties are used in measuring the fair value of such properties. The Company recorded impairment charges of $3.0 million, $792,000 and $3.7 million in 2011, 2010 and 2009, respectively, related to +its oil and natural gas properties. The Company determined the fair value of the impaired assets using internally developed unobservable inputs including future pricing and reserves (level 3 inputs in the fair value hierarchy of fair value +accounting). +F-13 +Table of Contents +On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability +based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer +horizontal wells using high capacity rigs). In connection with the Company’s ongoing planning process, it evaluated its then-current fleet of marketable drilling rigs in 2011, 2010 and 2009 and identified 53, four and 23 rigs, during each of +those years respectively, that it determined were impaired and would no longer be marketed as rigs based on its assessment of estimated expenditures to bring these rigs into condition to operate in the current environment as well as its assessment +of future demand and the suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to the Company’s other marketed rigs were +transferred to other rigs or to its yards to be used as spare equipment. The fair value of the remaining components of these rigs was estimated to be zero as there was no future cash flow expected and the associated net book value of $15.7 million +in 2011, $4.2 million in 2010 and $10.5 million in 2009 was expensed in the Company’s consolidated statements of operations as an impairment charge. +During 2010, the Company sold certain rights to explore and develop zones deeper than depths that it generally targets for certain of the oil and natural gas properties in which it has working interests. +The proceeds from this sale were approximately $22.3 million and the sale resulted in a gain on disposal of $20.1 million. +5. +Goodwill and Intangible Assets +Goodwill — Goodwill by operating segment as of December 31, 2011 and 2010 and changes for the years +then ended are as follows (in thousands): +Contract +Drilling +Pressure +Pumping +Total +Balance December 31, 2009 +$ +86,234 +$ +— +$ +86,234 +Acquisition +— +67,575 +67,575 +Balance December 31, 2010 +86,234 +67,575 +153,809 +Changes to goodwill +— +— +— +Balance December 31, 2011 +$ +86,234 +$ +67,575 +$ +153,809 +Goodwill was recorded in connection with a business combination in 2010 as a result of the Company’s +acquisition of the pressure pumping business of Key Energy Services, Inc. on October 1, 2010, as discussed further in Note 3. Approximately $53.2 million of this goodwill is expected to be deductible for tax purposes. There were no accumulated +impairment losses as of December 31, 2011 or 2010. +Goodwill is evaluated at least annually on December 31 to +determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been +determined to be its operating segments. Goodwill impairment is measured using a two-step impairment test. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If +the carrying value of a reporting unit exceeds its fair value the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any +remaining fair value representing the fair value of goodwill. +In connection with the Company’s annual goodwill impairment +assessment as of December 31, 2010, the Company estimated its enterprise value based on the market capitalization of the Company as determined by reference to the closing price of the Company’s common stock during the fifteen days before +and after year end. This enterprise value was allocated to the Company’s reporting units and it was determined that the fair values of the Company’s reporting units were in excess of their carrying value. As a result, the Company concluded +that no impairment of goodwill was indicated as of December 31, 2010. +F-14 +Table of Contents +In September 2011, the FASB issued an accounting standards update which provides entities +with the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, +after assessing the totality of events or circumstances, an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the two-step impairment test described above is +unnecessary. The provisions of this accounting standards update are effective for goodwill impairment tests performed for fiscal years beginning after December 15, 2011, however, early adoption is permitted. The Company elected to adopt the +provisions of the new goodwill impairment accounting standard issued in September 2011 in connection with its annual impairment assessment of goodwill as of December 31, 2011 and determined based on an assessment of qualitative factors that it +was more likely than not that the fair values of the Company’s reporting units were greater than their carrying amounts and further testing was not necessary. +In making this determination, the Company considered the continued demand experienced during 2011 for its services in the contract drilling and pressure pumping businesses. The Company also considered the +level of commodity prices for crude oil and natural gas, which influence its overall level of business activity in these operating segments. Additionally, current year operating results and forecasted operating results for the coming year were also +taken into account. The Company’s overall market capitalization and the large amount of calculated excess of the fair values of the Company’s reporting units over their carrying values and lack of significant changes in the key assumptions +from its 2010 quantitative Step 1 assessment of goodwill were also considered. The Company has undertaken extensive efforts in the past several years to upgrade its fleet of equipment and believes that it is positioned well from a competitive +standpoint to satisfy demand for high technology drilling of unconventional horizontal wells which should help mitigate decreases in demand for drilling conventional vertical wells that may result from recent decreases in natural gas prices. In the +event that market conditions weaken, the Company may be required to record an impairment of goodwill in its contract drilling or pressure pumping reporting units in the future, and such impairment could be material. +Intangible Assets — Intangible assets were recorded in the pressure pumping operating segment in connection with the fourth +quarter 2010 acquisition of the assets of the pressure pumping business discussed in Note 3. As a result of the purchase price allocation, the Company recorded intangible assets related to a non-compete agreement and the customer relationships +acquired. These intangible assets were recorded at fair value on the date of acquisition. +The non-compete agreement has a term +of three years from October 1, 2010. The value of this agreement was estimated using a with and without scenario where cash flows were projected through the term of the agreement assuming the agreement is in place and compared to cash flows +assuming the non-compete agreement was not in place. The intangible asset associated with the non-compete agreement is being amortized on a straight-line basis over the three-year term of the agreement. Amortization expense of $467,000 and $116,000 +was recorded in the year ended December 31, 2011 and 2010, respectively, associated with the non-compete agreement. +The +value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the time of the acquisition and taking into account a +contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of $3.6 million and $910,000 was recorded in the year ended December 31, 2011 and 2010, respectively, +associated with customer relationships. +F-15 +Table of Contents +The following table presents the gross carrying amount and accumulated amortization of +intangible assets as of December 31, 2011 and 2010 (in thousands): +2011 +2010 +Gross +Carrying +Amount +Accumulated +Amortization +Net +Carrying +Amount +Gross +Carrying +Amount +Accumulated +Amortization +Net +Carrying +Amount +Non-compete agreement +$ +1,400 +$ +(583 +) +$ +817 +$ +1,400 +$ +(116 +) +$ +1,284 +Customer relationships +25,500 +(4,553 +) +20,947 +25,500 +(910 +) +24,590 +Total intangible assets +$ +26,900 +$ +(5,136 +) +$ +21,764 +$ +26,900 +$ +(1,026 +) +$ +25,874 +6. +Accrued Expenses +Accrued expenses consisted of the following at December 31, 2011 and 2010 (in thousands): +2011 +2010 +Salaries, wages, payroll taxes and benefits +$ +58,692 +$ +39,866 +Workers’ compensation liability +66,121 +63,011 +Property, sales, use and other taxes +11,850 +6,682 +Insurance, other than workers’ compensation +6,012 +12,648 +Accrued interest payable +4,937 +4,879 +Deferred revenue — current +7,229 +10,220 +2009 Performance Unit Awards +3,640 +— +Other +6,148 +10,009 +$ +164,629 +$ +147,315 +Deferred revenue was recorded in 2010 in the purchase price allocation associated with the Company’s +acquisition of a pressure pumping business as discussed in Note 3. The deferred revenue relates to out-of-market pricing agreements that were in place at the acquired business at the time of the acquisition. The deferred revenue will be recognized +as pressure pumping revenue over the remaining term of the pricing agreements. Deferred revenue of approximately $8.4 million and $6.1 million was recognized in the years ended December 31, 2011 and 2010, respectively, related to these pricing +agreements. +7. +Asset Retirement Obligation +The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and +natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement +obligations during 2011 and 2010 (in thousands): +2011 +2010 +Balance at beginning of year +$ +3,063 +$ +2,955 +Liabilities incurred +361 +335 +Liabilities settled +(110 +) +(339 +) +Accretion expense +143 +112 +Revision in estimated costs of plugging oil and natural gas wells +(2 +) +— +Asset retirement obligation at end of year +$ +3,455 +$ +3,063 +8. +Long Term Debt +Credit Facilities — In March 2009, the Company entered into an unsecured revolving credit facility (the +“2009 Credit Facility”) with a maximum borrowing capacity of $240 million. The Company incurred debt issuance costs of approximately $6.2 million during 2009 in connection with the 2009 Credit Facility. These costs were being amortized to +interest expense over the contractual term of the 2009 Credit Facility. +F-16 +Table of Contents +On July 2, 2010, the Company entered into a 364-Day Credit Agreement (the “364-Day +Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent and lender. The 364-Day Credit Agreement was a committed senior unsecured single draw term loan credit facility that permitted a borrowing of up to $250 million, provided +that the loan must have been drawn no later than September 30, 2010 or, if an additional fee was paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement was 364 days after the date on which the closing conditions under +the 364-Day Credit Agreement were met. This facility was not drawn as of September 30, 2010 and it expired at that time. +On August 19, 2010, the Company entered into a Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A., as +administrative agent, letter of credit issuer, swing line lender and lender, and each of the other letter of credit issuer and lender parties thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving +credit facility and a term loan facility. The Credit Agreement replaced the 2009 Credit Facility. +The revolving credit +facility permits aggregate borrowings of up to $400 million and contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million. Subject to customary conditions, the Company may request +that the lenders’ aggregate commitments with respect to the revolving credit facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the revolving facility is August 19, 2013. +The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility is +payable in quarterly principal installments commencing November 19, 2010. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for +each of the subsequent eight quarterly installments and 5.00% of the original principal amount for the next subsequent three quarterly installments, with the remainder becoming due at maturity. The maturity date for the term loan facility is +August 19, 2014. +Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the +LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon the Company’s debt to capitalization +ratio. As of December 31, 2011, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans +times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon the Company’s debt to +capitalization ratio and was 0.50% as of December 31, 2011. +Each domestic subsidiary of the Company other than any +immaterial subsidiary has unconditionally guaranteed all existing and future indebtedness and liabilities of the Company and the other guarantors arising under the Credit Agreement and other loan documents. Such guarantees also cover obligations of +the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender or affiliate of a lender under the Credit Agreement. +The Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The Credit +Agreement also requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45% at any time. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of +(a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit +the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization +(“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. +As of December 31, 2011, +the Company had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 3.25% and $110 million principal amount outstanding under the revolving credit +F-17 +Table of Contents +facility at a weighted average interest rate of 4.05%. The carrying value of the balances outstanding under the term loan facility and the revolving credit facility approximate fair value due to +the frequency at which the interest rate resets. The Company had $40.6 million in letters of credit outstanding at December 31, 2011 and, as a result, had available borrowing capacity of approximately $249 million at that date. +Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal +amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private placement. A portion of the proceeds from the Notes was used to repay a $200 million borrowing on the Company’s revolving credit facility, +which had been drawn to fund a portion of the acquisition that closed on October 1, 2010 as discussed in Note 3. The fair value of the Notes at December 31, 2011 was approximately $316 million based on discounted cash flows associated with +the Notes using current market rates of interest. The Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Notes are guaranteed on a senior +unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries. +The Notes +bear interest at a rate of 4.97% per annum. The Company will pay interest on the Notes on April 5 and October 5 of each year. The Notes will mature on October 5, 2020. The Notes are prepayable at the Company’s option, in +whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. The Company must offer to prepay the Notes upon the occurrence of any change of control. In +addition, the Company must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid +Note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date. +The note +purchase agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio +of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit +the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges for +that same period. +Events of default under the note purchase agreement and the Credit Agreement include failure to pay +principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA +events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreement occurs and is continuing, then holders of a majority in principal amount of the Notes have the right to declare +all the Notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any Note, then until such defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and +payable. +The Company incurred approximately $10.8 million in debt issuance costs during 2010 in connection with the Credit +Agreement and the Senior Notes discussed above. These costs were deferred and will be recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs for the Credit Agreement +and the Senior Notes was approximately $2.4 million and $1.1 million for the years ended December 31, 2011 and 2010, respectively. +F-18 +Table of Contents +Presented below is a schedule of the principal repayment requirements of long-term debt by +fiscal year as of December 31, 2011 (in thousands): +Year ending December 31, +2012 +$ +10,000 +2013 +122,500 +2014 +70,000 +2015 +— +2016 +— +Thereafter +300,000 +Total +$ +502,500 +9. +Commitments, Contingencies and Other Matters +Commitments — As of December 31, 2011, the Company maintained letters of credit in the aggregate +amount of $40.6 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically renewed. As of December 31, 2011, no amounts had been drawn under the letters of credit. +As of December 31, 2011, the Company had commitments to purchase approximately $352 million of major equipment for its drilling and pressure pumping businesses. +The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants from certain vendors. +These agreements expire in 2013 and 2016. As of December 31, 2011, the remaining obligation under these agreements is approximately $42.5 million, of which materials with a total purchase price of approximately $13.5 million are expected to be +delivered during 2012. In the event that the required minimum quantities are not purchased during any contract year, the Company would be required to make a liquidated damages payment to the respective vendor for any shortfall. +In November of 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance, on a +non-revolving basis, up to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the +advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2011, advances of approximately $2.9 million had been made +under this agreement and no significant repayments had been made. +Contingencies — The Company’s operations +are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or +death, work stoppage, and serious damage to equipment and other property. The Company’s operations could also cause significant environmental and reservoir damages. These risks could expose the Company to substantial liability for personal +injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +Any contractual right to indemnification that the Company may have for any such risk, may be unenforceable or limited due to negligent or +willful acts of commission or omission by the Company, its subcontractors and/or suppliers. The Company’s customers may dispute, or be unable to meet, their contractual indemnification obligations to the Company due to financial, legal or other +reasons. Accordingly, the Company may be unable to transfer these risks to its customers by contract or indemnification agreements. Incurring a liability for which the Company is not fully indemnified or insured could have a material adverse effect +on its business, financial condition, cash flows and results of operations. +F-19 +Table of Contents +The Company has insurance coverage for comprehensive general liability, automobile +liability, workers’ compensation and employer’s liability, and certain other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For +example, the Company generally maintains a $1.0 million per occurrence deductible on its workers’ compensation and equipment insurance coverages and a $2.0 million per occurrence self insured retention on its general liability insurance +coverage. The Company self-insures a number of other risks, including loss of earnings and business interruption, and does not carry a significant amount of insurance to cover risks of underground reservoir damage. If a significant accident or other +event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations. Accrued +expenses related to insurance claims are set forth in Note 6. +The Company is party to various legal proceedings arising in the +normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows. +Other Matters — The Company has Change in Control Agreements with its Chairman of the Board, Chief Executive +Officer, two Senior Vice Presidents and its General Counsel (the “Key Employees”). Each Change in Control Agreement generally has an initial term with automatic twelve-month renewals unless the Company notifies the Key Employee at least +ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the term of the agreement and the Key Employee’s employment is terminated (i) by the Company other +than for cause or other than automatically as a result of death, disability or retirement, or (ii) by the Key Employee for good reason (as those terms are defined in the Change in Control Agreements), then the Key Employee shall generally be +entitled to, among other things: +• +a bonus payment equal to the greater of the highest bonus paid after the Change in Control Agreement was entered into and the average of the two annual +bonuses earned in the two fiscal years immediately preceding a change in control (such bonus payment prorated for the portion of the fiscal year preceding the termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the Board and Chief Executive Officer), 2 times (in the case of the Senior Vice +Presidents) or 1.5 times (in the case of the General Counsel) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three annual bonuses earned by the Key Employee for the three fiscal +years preceding the termination date; and +• +continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board and Chief Executive Officer) +or two years (in the case of the Senior Vice Presidents and General Counsel). +Each Change in Control +Agreement provides the Key Employee with a full gross-up payment for any excise taxes imposed on payments and benefits received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the +gross-up payment. +F-20 +Table of Contents +10. +Stockholders’ Equity +Cash Dividends — The Company paid cash dividends during the years ended December 31, 2009, 2010 and +2011 as follows: +Per Share +Total +(in thousands) +2009: +Paid on March 31, 2009 +$ +0.05 +$ +7,655 +Paid on June 30, 2009 +0.05 +7,675 +Paid on September 30, 2009 +0.05 +7,675 +Paid on December 30, 2009 +0.05 +7,676 +Total cash dividends +$ +0.20 +$ +30,681 +2010: +Paid on March 30, 2010 +$ +0.05 +$ +7,677 +Paid on June 30, 2010 +0.05 +7,706 +Paid on September 30, 2010 +0.05 +7,704 +Paid on December 30, 2010 +0.05 +7,709 +Total cash dividends +$ +0.20 +$ +30,796 +2011: +Paid on March 30, 2011 +$ +0.05 +$ +7,708 +Paid on June 30, 2011 +0.05 +7,772 +Paid on September 30, 2011 +0.05 +7,777 +Paid on December 30, 2011 +0.05 +7,788 +Total cash dividends +$ +0.20 +$ +31,045 +On February 1, 2012, the Company’s Board of Directors approved a cash dividend on its common +stock in the amount of $0.05 per share to be paid on March 30, 2012 to holders of record as of March 15, 2012. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will +depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of the Company’s common stock in open market or privately +negotiated transactions. During the year ended December 31, 2009, the Company purchased 5,715 shares of its common stock under the program at a cost of approximately $79,000. During the year ended December 31, 2010, the Company purchased +8,743 shares of its common stock under the program at a cost of approximately $123,000. During the year ended December 31, 2011, the Company purchased 8,689 shares of its common stock under the program at a cost of approximately $255,000. As of +December 31, 2011, the Company is authorized to purchase approximately $113 million of the Company’s outstanding common stock under the program. Shares purchased under the program are accounted for as treasury stock. +The Company purchased 135,068, 117,083 and 114,983 shares of treasury stock from employees during 2011, 2010 and 2009, respectively. These +shares were purchased at fair market value upon the vesting of restricted stock to provide the employees with the funds necessary to satisfy payroll tax withholding obligations. The total purchase price for these shares was approximately $4.1 +million, $1.7 million and $1.5 million in 2011, 2010 and 2009, respectively. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) and not pursuant to the stock +buyback program. +F-21 +Table of Contents +11. +Stock-based Compensation +The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the +cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance +conditions. The Company’s share-based awards also include both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as liability awards. Share-settled performance unit awards are +accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest. +The Company’s shareholders have approved the 2005 Plan, and the Board of Directors adopted a resolution that no future grants would +be made under any of the Company’s other previously existing plans. During 2010, the Company amended the 2005 Plan to, among other things, increase the total number of shares authorized for grant from 10,250,000 to 15,250,000. The +Company’s share-based compensation plans at December 31, 2011 follow: +Plan Name +Shares +Authorized +for Grant +Awards +Outstanding +Shares +Available +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended +15,250,000 +6,293,495 +4,399,951 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”) +— +1,983,300 +— +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”) +— +35,800 +— +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers the plan. +• +All employees including officers and directors are eligible for awards. +• +The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and three +years for employees. +• +The Compensation Committee sets the term of awards and no option term can exceed 10 years. +• +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. As of December 31, 2011, non-incentive stock options, restricted stock awards, restricted stock units and performance unit awards +had been granted under the plan. +Options granted under the 1997 Plan typically vested over three or five +years as dictated by the Compensation Committee. These options have terms of no more than ten years. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four years. +Options granted under the 2001 Plan typically vested over +five years as dictated by the Compensation Committee. These options have terms of no more than 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. +Stock Options — The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton +valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. +F-22 +Table of Contents +The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time +the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the years ended December +31, 2011, 2010 and 2009 follow: +2011 +2010 +2009 +Volatility +45.97 +% +45.98 +% +49.90 +% +Expected term (in years) +5.00 +5.00 +4.00 +Dividend yield +0.67 +% +1.35 +% +1.67 +% +Risk-free interest rate +2.34 +% +2.47 +% +1.67 +% +Stock option activity for the year ended December 31, 2011 follows: +Shares +Weighted-average +exercise price +Outstanding at beginning of year +7,710,102 +$ +19.58 +Granted +419,500 +$ +30.28 +Exercised +(1,048,307 +) +$ +16.04 +Cancelled +— +$ +— +Expired +— +$ +— +Outstanding at end of year +7,081,295 +$ +20.73 +Exercisable at end of year +6,077,635 +$ +20.69 +Options outstanding at December 31, 2011 have an aggregate intrinsic value of approximately $17.9 +million and a weighted-average remaining contractual term of 5.3 years. Options exercisable at December 31, 2011 have an aggregate intrinsic value of approximately $14.6 million and a weighted-average remaining contractual term of 4.8 years. +Additional information with respect to options granted, vested and exercised during the years ended December 31, 2011, 2010 and 2009 follows: +2011 +2010 +2009 +Weighted-average grant date fair value of stock options granted (per share) +$ +12.24 +$ +5.69 +$ +4.71 +Grant date fair value of stock options vested during the year (in thousands) +$ +5,639 +$ +5,553 +$ +6,973 +Aggregate intrinsic value of stock options exercised (in thousands) +$ +12,663 +$ +523 +$ +510 +As of December 31, 2011, options to purchase 1,003,660 shares were outstanding and not vested. All of +these non-vested options are expected to ultimately vest. Additional information as of December 31, 2011 with respect to these non-vested options follows: +Aggregate intrinsic value +$3.3 million +Weighted-average remaining contractual term +8.56 years +Weighted-average remaining expected term +3.45 years +Weighted-average remaining vesting period +1.52 years +Unrecognized compensation cost +$6.7 million +Restricted Stock — For all restricted stock awards to date, shares of common stock were issued +when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. The Company +uses the straight-line method to recognize periodic compensation cost over the vesting period. +F-23 +Table of Contents +Restricted stock activity for the year ended December 31, 2011 follows: +Shares +Weighted- +average Grant +Date Fair Value +Non-vested restricted stock outstanding at beginning of year +1,114,051 +$ +16.05 +Granted +782,300 +$ +30.46 +Vested +(599,394 +) +$ +17.60 +Forfeited +(83,158 +) +$ +22.58 +Non-vested restricted stock outstanding at end of year +1,213,799 +$ +24.13 +As of December 31, 2011, approximately 1.1 million shares of non-vested restricted stock +outstanding are expected to vest. Additional information as of December 31, 2011 with respect to these non-vested shares follows: +Aggregate intrinsic value +$22.6 million +Weighted-average remaining vesting period +1.90 years +Unrecognized compensation cost +$22.6 million +Restricted Stock Units — For all restricted stock unit awards made to date, shares of common +stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units. +Restricted stock unit activity for the year ended December 31, 2011 follows: +Shares +Weighted +Average +Grant Date +Fair Value +Non-vested restricted stock units outstanding at beginning of year +17,834 +$ +19.73 +Granted +10,000 +$ +30.63 +Vested +(10,333 +) +$ +23.94 +Forfeited +— +$ +— +Non-vested restricted stock units outstanding at end of year +17,501 +$ +23.47 +Performance Unit Awards. In 2009, the Company granted cash-settled +performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provide for those executive officers to receive a cash payment upon the achievement of certain performance goals established +by the Compensation Committee during a specified period. The performance period for the 2009 Performance Units is the period from April 1, 2009 through March 31, 2012, but can extend through March 31, 2014 in certain circumstances. +The performance goals for the 2009 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee of the Board of +Directors. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the performance units. Generally, the recipients will receive a +base payment if the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25 th percentile but less than the 50 th percentile, two times the base if at or above the 50 th percentile but less than the 75 th percentile, and four times the base if at the 75 th percentile or higher. The total base amount with respect to the 2009 Performance Units is approximately $1.7 million. +Because the 2009 Performance Units are to be settled in cash at the end of the performance period, they are accounted for as liability awards and the Company’s pro-rated obligation is measured at estimated fair value at the end of each +reporting period using a Monte Carlo simulation model. As of December 31, 2011 this pro-rated obligation was approximately $3.6 million and is included in the caption “accrued expenses” in the liabilities section of the consolidated +balance sheet. Compensation expense associated with the 2009 Performance Units was approximately $1.3 million, $1.5 million and $859,000 for the years ended December 31, 2011, 2010 and 2009, respectively. +F-24 +Table of Contents +In 2010 and 2011, the Company granted stock-settled performance unit +awards to certain executive officers (the “2010 Performance Units” and the “2011 Performance Units”, respectively). The 2010 Performance Units and the 2011 Performance Units provide for those executive officers to receive a grant +of shares of stock upon the achievement of certain performance goals established by the Compensation Committee during a specified period. The performance period for the 2010 Performance Units is the period from April 1, 2010 through +March 31, 2013, but can extend through March 31, 2015 in certain circumstances. The performance period for the 2011 Performance Units is the period from April 1, 2011 through March 31, 2014, but can extend through March 31, +2016 in certain circumstances. The performance goals for the 2010 Performance Units and the 2011 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer +group determined by the Compensation Committee of the Board of Directors. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of +the respective performance units. Generally, the recipients will receive a base number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 25 th percentile, two times the base if at the 50 th percentile, and four times the base if at the 75 th percentile or higher. The grant of shares when achievement is +between the 25 th and 75 th percentile will be determined on a pro-rata basis. The total base +number of shares with respect to the 2010 Performance Units is 89,375 shares and the total base number of shares with respect to the 2011 Performance Units is 72,188 shares. Because the 2010 and 2011 Performance Units are stock-settled awards, they +are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the 2010 Performance Units as of the date of grant was approximately $3.1 million and the fair value of the +2011 Performance Units as of the date of grant was approximately $5.6 million. This fair value is recognized on a straight-line basis over the performance period. Compensation expense associated with the 2010 Performance Units was approximately $1.0 +million and $779,000 for the years ended December 31, 2011 and 2010, respectively. Compensation expense associated with the 2011 Performance Units was approximately $1.4 million for the year ended December 31, 2011. +Dividends on Equity Awards — Non-forfeitable cash dividends and dividend equivalents paid on equity awards are recognized as +follows: +• +Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest. +• +Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do +not vest. +• +Dividend equivalents are recognized as additional compensation cost for restricted stock units. +12. +Leases +The Company incurred rent expense of $35.0 million, $18.1 million and $11.9 million for the years 2011, 2010 and 2009, +respectively. Rent expense is primarily related to short-term equipment rentals that are generally passed through to customers. The Company’s obligations under non-cancelable operating lease agreements are not material to its operations or cash +flows. +F-25 +Table of Contents +13. +Income Taxes +Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended +December 31, 2011, 2010 and 2009 are as follows (in thousands): +2011 +2010 +2009 +Federal income tax expense (benefit): +Current +$ +16,336 +$ +(77,310 +) +$ +(117,493 +) +Deferred +146,842 +145,198 +103,574 +163,178 +67,888 +(13,919 +) +State income tax expense (benefit): +Current +6,056 +19 +(1,883 +) +Deferred +13,196 +3,246 +(1,875 +) +19,252 +3,265 +(3,758 +) +Foreign income tax expense (benefit): +Current +6,579 +2,657 +338 +Deferred +(1,071 +) +(954 +) +(256 +) +5,508 +1,703 +82 +Total income tax expense (benefit): +Current +28,971 +(74,634 +) +(119,038 +) +Deferred +158,967 +147,490 +101,443 +Total income tax expense (benefit) +$ +187,938 +$ +72,856 +$ +(17,595 +) +The difference between the statutory federal income tax rate and the effective income tax rate for the +years ended December 31, 2011, 2010 and 2009 is summarized as follows: +2011 +2010 +2009 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +2.5 +1.1 +4.7 +Permanent differences +(0.1 +) +2.3 +(5.7 +) +Other, net +(0.6 +) +(0.2 +) +0.1 +Effective tax rate +36.8 +% +38.2 +% +34.1 +% +The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 +(as revised by the Emergency Economic Stabilization Act of 2008,) and allows a deduction of 6% in 2009 and 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent differences for 2010 and +2009 reflect the recapture of a portion of this deduction due to the carryback of the 2010 and 2009 net operating losses to prior years. This recapture resulted in a negative effective rate impact in 2009 due to the Company having a loss before +income taxes in that year. The permanent difference for 2011 does not include any deduction as it is limited to taxable income and the Company had a tax loss in 2011. +F-26 +Table of Contents +The tax effect of significant temporary differences representing deferred tax assets and +liabilities and changes therein were as follows (in thousands): +December 31, +2011 +Net +Change +December 31, +2010 +Net +Change +December 31, +2009 +Net +Change +December 31, +2008 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +114,576 +$ +114,576 +$ +— +$ +— +$ +— +$ +— +$ +— +Workers’ compensation allowance +24,004 +714 +23,290 +(1,334 +) +24,624 +(1,360 +) +25,984 +Other +18,800 +146 +18,654 +(962 +) +19,616 +(2,735 +) +22,351 +157,380 +115,436 +41,944 +(2,296 +) +44,240 +(4,095 +) +48,335 +Non-current: +Net operating loss carryforwards +18,434 +11,969 +6,465 +1,593 +4,872 +4,872 +— +Expense associated with employee stock options +12,728 +1,476 +11,252 +2,123 +9,129 +2,500 +6,629 +Federal benefit of foreign deferred tax liabilities +— +— +— +(9,160 +) +9,160 +(256 +) +9,416 +Federal benefit of state deferred tax liabilities +20,260 +7,105 +13,155 +3,383 +9,772 +2,702 +7,070 +Other +10,670 +(5,361 +) +16,031 +6,546 +9,485 +4,120 +5,365 +62,092 +15,189 +46,903 +4,485 +42,418 +13,938 +28,480 +Total deferred tax assets +219,472 +130,625 +88,847 +2,189 +86,658 +9,843 +76,815 +Deferred tax liabilities: +Current: +Other +(14,655 +) +474 +(15,129 +) +(3,766 +) +(11,363 +) +1,044 +(12,407 +) +Non-current: +Property and equipment basis difference +(835,823 +) +(289,168 +) +(546,655 +) +(133,542 +) +(413,113 +) +(110,786 +) +(302,327 +) +Other +(12,901 +) +(1,231 +) +(11,670 +) +(709 +) +(10,961 +) +(7,091 +) +(3,870 +) +(848,724 +) +(290,399 +) +(558,325 +) +(134,251 +) +(424,074 +) +(117,877 +) +(306,197 +) +Total deferred tax liabilities +(863,379 +) +(289,925 +) +(573,454 +) +(138,017 +) +(435,437 +) +(116,833 +) +(318,604 +) +Net deferred tax liability +$ +(643,907 +) +$ +(159,300 +) +$ +(484,607 +) +$ +(135,828 +) +$ +(348,779 +) +$ +(106,990 +) +$ +(241,789 +) +In assessing the realizability of deferred tax assets, management considers whether it is more likely than +not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company expects the deferred tax assets at December 31, 2011 and +2010 to be realized as a result of the reversal of existing taxable temporary differences giving rise to deferred tax liabilities and the generation of taxable income; therefore, no valuation allowance is considered necessary. +F-27 +Table of Contents +Other deferred tax assets consist primarily of the tax effect of various allowance accounts +and tax-deferred expenses expected to generate future tax benefits of approximately $29.5 million. Other deferred tax liabilities consist primarily of the tax effect of receivables from insurance companies and tax-deferred income not yet recognized +for tax purposes. +For income tax purposes, the Company generated approximately $327 million of federal net operating losses +and approximately $136 million of state net operating losses during the year ended December 31, 2011. Of these amounts, approximately $11.1 million will be carried back to prior years, and the remaining balance can be carried forward to future +years along with prior year carryovers in the amount of $118 million. Net operating losses that can be carried forward, if unused, are scheduled to expire as follows: 2014 — $9.6 million; 2015 — $12.9 million; 2016 — $8.2 million; +2018 — $2.4 million; 2028 — $15.3 million; 2029 — $59.8 million; 2030 — $35.7 million and 2031 — $426 million. +As of December 31, 2011, the Company had no unrecognized tax benefits. The Company has established a policy to account for interest and penalties related to uncertain income tax positions as +operating expenses. As of December 31, 2011, the tax years ended December 31, 2008 through December 31, 2010 are open for examination by U.S. taxing authorities. As of December 31, 2011, the tax years ended December 31, 2007 +through December 31, 2010 are open for examination by Canadian taxing authorities. +On January 1, 2010, the Company +converted its Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 +million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets. +As a result of the above conversion, the Company’s Canadian assets are no longer directly subject to United States taxation, provided +that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and intends to do so for the foreseeable future. As a +result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $25.2 million as of December 31, 2011. +14. +Employee Benefits +The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses +of approximately $4.6 million in 2011, $3.1 million in 2010 and $2.8 million in 2009 for the Company’s cash contributions to the plan. +15. +Business Segments +The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business +segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a +distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for +purposes of determining resource allocation and assessing performance. As discussed in Note 2, in January 2010, the Company exited the drilling and completion fluids services business which previously was reported as a business segment. Operating +results for that business for the years ended December 31, 2010 and 2009 are presented as discontinued operations in the consolidated statements of operations. Also included in discontinued operations for the year ended December 31, 2011 +and 2010 are the operating results for an electric wireline business that was acquired on October 1, 2010 and sold in January 2011. +Contract Drilling — The Company markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2011, the Company had 328 marketable +land-based drilling rigs, of which 64 were based in west Texas and southeastern New Mexico; 73 in north central and east Texas, northern +F-28 +Table of Contents +Louisiana and Mississippi; 48 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and North Dakota); 62 in south Texas and southern Louisiana; 27 in the Texas panhandle, Oklahoma and +Arkansas; 34 in the Appalachian Basin and 20 in western Canada. +For the years ended December 31, 2011, 2010 and 2009, +contract drilling revenue earned in Canada was $106 million, $65.7 million and $45.4 million, respectively. Additionally, long-lived assets within the contract drilling segment located in Canada totaled $69.8 million and $70.7 million as of +December 31, 2011 and 2010, respectively. +Pressure Pumping — The Company provides pressure pumping services +to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Well stimulation involves +processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. Cementing is the process of inserting material between the hole and the pipe to center and stabilize the pipe in the hole. +Oil and Natural Gas — The Company owns and invests in oil and natural gas assets as a non-operating working +interest owner. The Company’s oil and natural gas interests are located primarily in Texas and New Mexico. +F-29 +Table of Contents +The following tables summarize selected financial information relating to the Company’s +business segments (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Revenues: +Contract drilling +$ +1,673,629 +$ +1,085,722 +$ +600,423 +Pressure pumping +845,803 +350,608 +161,441 +Oil and natural gas +50,559 +30,425 +21,218 +Total segment revenues +2,569,991 +1,466,755 +783,082 +Elimination of intercompany revenues(a) +(4,048 +) +(3,824 +) +(1,136 +) +Total revenues +$ +2,565,943 +$ +1,462,931 +$ +781,946 +Income (loss) from continuing operations before income taxes: +Contract drilling +$ +346,083 +$ +140,483 +$ +(11,219 +) +Pressure pumping +193,440 +62,194 +1,017 +Oil and natural gas +23,982 +12,455 +950 +563,505 +215,132 +(9,252 +) +Corporate and other +(42,903 +) +(37,019 +) +(35,577 +) +Net (loss) gain on asset disposals(b) +4,999 +22,812 +(3,385 +) +Interest income +187 +1,674 +381 +Interest expense +(15,652 +) +(12,772 +) +(4,148 +) +Other +582 +927 +426 +Income (loss) from continuing operations before income taxes +$ +510,718 +$ +190,754 +$ +(51,555 +) +Identifiable assets: +Contract drilling +$ +3,252,116 +$ +2,678,250 +$ +2,129,567 +Pressure pumping +748,643 +533,597 +213,094 +Oil and natural gas +44,990 +36,508 +25,355 +Corporate and other(c) +176,152 +174,676 +294,136 +Total assets +$ +4,221,901 +$ +3,423,031 +$ +2,662,152 +Depreciation, depletion, amortization and impairment: +Contract drilling +$ +344,312 +$ +280,458 +$ +248,424 +Pressure pumping +73,279 +40,724 +27,589 +Oil and natural gas +16,962 +10,950 +12,927 +Corporate and other +2,726 +1,361 +907 +Total depreciation, depletion, amortization and impairment +$ +437,279 +$ +333,493 +$ +289,847 +Capital expenditures: +Contract drilling +$ +784,686 +$ +655,550 +$ +395,376 +Pressure pumping +198,061 +51,064 +43,144 +Oil and natural gas +22,884 +23,067 +7,341 +Corporate and other +5,947 +8,409 +6,785 +Total capital expenditures +$ +1,011,578 +$ +738,090 +$ +452,646 +(a) +Includes contract drilling intercompany revenues related to drilling services provided to the oil and natural gas exploration and production segment. +F-30 +Table of Contents +(b) +Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or +losses have been separately presented and excluded from the results of specific segments. +(c) +Corporate and other assets primarily include identifiable assets associated with assets held for sale as well as cash on hand, income taxes receivable and certain +deferred federal income tax assets. +16. +Concentrations of Credit Risk +Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of +demand deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial institutions. At December 31, 2011 and 2010, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands): +2011 +2010 +Deposits in FDIC and SIPC-insured institutions under insurance limits +$ +289 +$ +1,523 +Deposits in FDIC and SIPC-insured institutions over insurance limits +50,035 +51,625 +Deposits in foreign banks +18,823 +11,533 +69,147 +64,681 +Less outstanding checks and other reconciling items +(45,201 +) +(37,069 +) +Cash and cash equivalents +$ +23,946 +$ +27,612 +Concentrations of credit risk with respect to trade receivables are primarily focused on companies +involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides services. As is general industry practice, the Company +typically does not require customers to provide collateral. No significant losses from individual customers were experienced during the years ended December 31, 2011, 2010 or 2009. No provision for bad debts was recognized in 2011. The Company +recorded a provision for bad debts for 2010 and 2009 of $(2.0) million and $3.8 million, respectively. +17. +Fair Values of Financial Instruments +The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to +the short-term maturity of these items. +The estimated fair value of the Company’s outstanding debt balances (including +current portion) as of December 31, 2011 and 2010 is set forth below (in thousands): +December 31, 2011 +December 31, 2010 +Carrying +Value +Fair +Value +Carrying +Value +Fair +Value +Borrowings under Credit Agreement: +Revolving credit facility +$ +110,000 +$ +110,000 +$ +— +$ +— +Term loan facility +92,500 +92,500 +98,750 +98,750 +Senior Notes +300,000 +315,942 +300,000 +289,625 +Total debt +$ +502,500 +$ +518,442 +$ +398,750 +$ +388,375 +The carrying value of the balance outstanding under the term loan facility and revolving credit facility +approximates fair value as both facilities have a floating interest rate that adjusts at each quarterly interest payment date. The fair value of the 4.97% Series A Senior Notes at December 31, 2011 and 2010 is based on discounted cash flows +associated with the Senior Notes using current market rates of interest at those respective dates. These fair value estimates are based on observable market inputs and are considered level 2 fair value estimates in the fair value hierarchy of fair +value accounting. +F-31 +Table of Contents +18. +Quarterly Financial Information (in thousands, except per share amounts) (unaudited) +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +2010 +Operating revenues +$ +271,598 +$ +306,992 +$ +378,663 +$ +505,678 +Operating income +7,831 +45,757 +52,509 +94,828 +Income from continuing operations, net of income taxes +4,186 +29,528 +29,374 +54,810 +Loss from discontinued operations, net of income taxes +— +— +— +(956 +) +Net income +4,186 +29,528 +29,374 +53,854 +Basic income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.36 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +Diluted income (loss) per common share: +From continuing operations +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +(0.01 +) +Net income +$ +0.03 +$ +0.19 +$ +0.19 +$ +0.35 +2011 +Operating revenues +$ +567,404 +$ +600,064 +$ +673,828 +$ +724,647 +Operating income +117,547 +131,860 +132,294 +143,900 +Income from continuing operations, net of income taxes +71,619 +81,638 +81,928 +87,595 +Loss from discontinued operations, net of income taxes +(367 +) +— +— +— +Net income +71,252 +81,638 +81,928 +87,595 +Basic income (loss) per common share: +From continuing operations +$ +0.46 +$ +0.53 +$ +0.53 +$ +0.56 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +0.00 +Net income +$ +0.46 +$ +0.53 +$ +0.53 +$ +0.56 +Diluted income (loss) per common share: +From continuing operations +$ +0.46 +$ +0.52 +$ +0.53 +$ +0.56 +From discontinued operations +$ +0.00 +$ +0.00 +$ +0.00 +$ +0.00 +Net income +$ +0.46 +$ +0.52 +$ +0.53 +$ +0.56 +As discussed in Note 2, the Company exited the drilling and completion fluids services business in January +2010 and sold a recently acquired wireline business in January 2011. The results of operations related to those businesses have been reclassified and presented as discontinued operations in the quarterly financial information above. +F-32 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +Charged to +Costs and +Expenses +Deductions(1) +Ending +Balance +(In thousands) +Year Ended December 31, 2011 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +5,114 +$ +0 +$ +227 +$ +4,887 +Year Ended December 31, 2010 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +10,911 +$ +(2,000 +) +$ +3,797 +$ +5,114 +Year Ended December 31, 2009 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +9,330 +$ +4,700 +$ +3,119 +$ +10,911 +(1) +Consists of uncollectible accounts written off. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form 10-K to be signed on its behalf by the +undersigned, thereunto duly authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ Douglas J. Wall +Douglas J. Wall +President and Chief Executive Officer +Date: February 10, 2012 +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 February 10, 2012. +Signature +Title +/s/ Mark S. Siegel +Chairman of the Board +Mark S. Siegel +/s/ Douglas J. Wall +President and Chief Executive Officer +Douglas J. Wall +(Principal Executive Officer) +/s/ John E. Vollmer III +Senior Vice President — Corporate Development, +John E. Vollmer III +Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Gregory W. Pipkin +Chief Accounting Officer and +Gregory W. Pipkin +Assistant Secretary +(Principal Accounting Officer) +/s/ Kenneth N. Berns +Senior Vice President and Director +Kenneth N. Berns +/s/ Charles O. Buckner +Director +Charles O. Buckner +/s/ Curtis W. Huff +Director +Curtis W. Huff +/s/ Terry H. Hunt +Director +Terry H. Hunt +/s/ Kenneth R. Peak +Director +Kenneth R. Peak +/s/ Cloyce A. Talbott +Director +Cloyce A. Talbott +Table of Contents +EXHIBIT INDEX +2.1 +Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure +Pumping Services, LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +2.2 +Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +2.3 +Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +3.1 +Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 +and incorporated herein by reference). +3.2 +Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended +June 30, 2004 and incorporated herein by reference). +3.3 +Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +3.4 +Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated +herein by reference). +4.1 +Restated Certificate of Incorporation, as amended (See Exhibits 3.1, 3.2 and 3.3). +4.2 +Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). +10.1 +For additional material contracts, see Exhibit 4.2. +10.2 +Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company's Registration +Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* +10.3 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarterly +period ended June 30, 2003 and incorporated herein by reference).* +10.4 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q +for the quarterly period ended June 30, 2004 and incorporated herein by reference).* +10.5 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company's Current Report on Form 8-K, and incorporated herein by +reference).* +10.6 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated +herein by reference). +Table of Contents +10.7 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +10.8 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.9 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.10 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q and +incorporated herein by reference).* +10.11 +Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time (filed February 19, 2010 +as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference).* +10.12 +Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).* +10.13 +Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).* +10.14 +Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John +E. Vollmer III (filed 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).* +10.15 +Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form +10-K, as amended, and incorporated herein by reference).* +10.16 +Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on September 24, 2007 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K, and incorporated herein by reference).* +10.17 +Employment Agreement, effective as of January 1, 2012, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb.*+ +10.18 +Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry +H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 as Exhibit 10.11 to the Company's Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and +incorporated herein by reference).* +10.19 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as +Exhibit 10.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI Energy, Inc. and Douglas J. Wall (filed September 4, 2007 as +Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* +Table of Contents +10.21 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 +as Exhibit 10.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.22 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, +2004 as Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.23 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.24 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit +10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.25 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to +the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.26 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.27 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as +Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* +10.28 +Credit Agreement dated August 19, 2010, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer and lender and each +of the other letter of credit issuer and lender parties thereto (filed August 19, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +10.29 +Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.+ +23.1 +Consent of Independent Registered Public Accounting Firm.+ +31.1 +Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +31.2 +Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +32.1 +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of +2002.+ +101 +The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting +Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to Consolidated +Financial Statements, tagged as blocks of text.+ +* +Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. ++ +Filed herewith. \ No newline at end of file diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/filing_metadata.csv b/raw/filings/0000889900/2011/0001193125-12-052274/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..bfad1d72fe1c3fd37743a1fc94f472611a5d3052 --- /dev/null +++ b/raw/filings/0000889900/2011/0001193125-12-052274/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2012-02-10,2011-12-31,2012-02-10T20:21:52.000Z,0001193125-12-052274,d261327d10k.htm,FORM 10-K,11413886,1,0,https://www.sec.gov/Archives/edgar/data/889900/000119312512052274/d261327d10k.htm,https://www.sec.gov/Archives/edgar/data/889900/000119312512052274/,2011,2011,1 diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/item1.txt b/raw/filings/0000889900/2011/0001193125-12-052274/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..f4a8abace70526a5626ff9d07b55260962026ebb --- /dev/null +++ b/raw/filings/0000889900/2011/0001193125-12-052274/item1.txt @@ -0,0 +1,383 @@ +Item 1. +Business +Available Information +This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website ( www.patenergy.com ) as soon as reasonably practicable after we electronically file such material with, or furnish it to, +the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at +2 +Table of Contents +1-800-SEC-0330. The SEC maintains an internet site ( www.sec.gov ) that contains reports, proxy and information statements and other information regarding issuers that file electronically +with the SEC. +Overview +We own and operate one of the largest fleets of land-based drilling rigs in the United States. 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, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia, Ohio and western Canada. +As of December 31, 2011, we had a drilling fleet that consisted of 328 marketable land-based drilling rigs. A drilling rig includes +the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without +significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components. +We provide +pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. +We also own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas +working interests are located primarily in Texas and New Mexico. +Prior to January 20, 2010, we provided drilling fluids, +completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. We sold our drilling and completion fluids services business on January 20, 2010. +On October 1, 2010, we acquired the assets and operations of a pressure pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on +January 27, 2011. The results of our drilling and completion fluids services business and our electric wireline business are presented as discontinued operations in this Report. +Industry Segments +Our revenues, operating profits and identifiable assets +are primarily attributable to three industry segments: +• +contract drilling services, +• +pressure pumping services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2011 and 2010. In 2009, our pressure pumping services and oil and natural gas exploration and production segments had operating profits and our +contract drilling services segment had an operating loss. +See “Management’s Discussion and Analysis of Financial +Condition and Results of Operations” and Note 15 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments. +Contract Drilling Operations +General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2011, we had 328 marketable land-based drilling rigs based in +the following regions: +• +64 in west Texas and southeastern New Mexico, +• +73 in north central and east Texas, northern Louisiana and Mississippi, +• +48 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and North Dakota), +• +62 in south Texas and southern Louisiana, +3 +Table of Contents +• +27 in the Texas panhandle, Oklahoma and Arkansas, +• +34 in the Appalachian Basin, and +• +20 in western Canada. +Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,250 feet to 25,000 feet. Of these drilling rigs, 145 are electric rigs and 183 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. We also have a substantial inventory of drill pipe and drilling rig components, which +may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs. +Drilling rigs are +typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each +year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent over $1.8 billion during the last three years on capital expenditures to (1) build new land drilling +rigs and (2) modify, upgrade and maintain our drilling fleet. During fiscal years 2011, 2010 and 2009, we spent approximately $785 million, $656 million and $395 million, respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected +for a particular job. +Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts +and other related rig equipment, fuel and other materials and qualified personnel. Some of these have been in short supply from time to time. +Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term +basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently one to three years) and provide for the use of +the drilling rig to drill multiple wells. During 2011, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 22 days. +Our 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. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for the payment of an early termination payment to us in the event that +the contract is terminated by the customer. We believe that our drilling contracts generally provide for identification rights and obligations that are customary for the markets in which we conduct those operations; however, each drilling contract +contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions or other factors. +Our drilling 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 job 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. +Under daywork contracts, we provide the drilling rig and crew to the customer. +The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are +interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. Except for two wells drilled under footage contracts in 2009, all of +the wells we drilled in 2011, 2010 and 2009 were under daywork contracts. +4 +Table of Contents +Under footage contracts, we contract to drill a well to a certain depth under specified +conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the +agreed-upon depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires +more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor typically assumes certain risks +associated with loss of the well from fire, blowouts and other risks. We drilled two wells under footage contracts in 2009, and we did not drill any wells under footage contracts in 2011 or 2010. +Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey +arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, +casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. +Compensation occurs only when the agreed-upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we +have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and +losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey +contracts in the past, we did not enter into any turnkey contracts in the past three years. +Contract Drilling Activity +— Information regarding our contract drilling activity for the last three years follows: +Year Ended December 31, +2011 +2010 +2009 +Average rigs operating per day(1) +216 +168 +91 +Number of rigs operated during the year +250 +220 +243 +Number of wells drilled during the year +3,529 +2,919 +1,539 +Number of operating days +78,758 +61,244 +33,394 +(1) +A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. +Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to +match the needs of our customers. While conventional wells remain an important source of natural gas and oil, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for natural gas and +oil in North America. +5 +Table of Contents +To address our customers’ needs for drilling wells in the newer horizontal shale and +other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling fleet. We have delivered new APEX™ rigs to the market and have made performance and safety improvements to existing high +capacity rigs. APEX 1500™ rigs are 1,500 horsepower electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other highly automated pipe handling equipment. APEX 1000™ rigs are +1,000 horsepower electric rigs with advanced technology equipment similar to the APEX 1500™ rigs, but with a more compact design to fit on smaller locations. APEX Walking™ rigs are designed to efficiently drill multiple wells from a single +pad, by “walking” between the wellbores without requiring time to lower the mast and lay down the drill pipe. As of December 31, 2011 our drilling fleet was comprised of the following: +Number of Rigs +Classification +U.S. +Canada +Total +APEX 1500™ rigs +38 +— +38 +APEX 1000™ rigs (including eight with walking systems) +13 +— +13 +APEX Walking™ rigs +40 +— +40 +Other electric rigs +46 +8 +54 +Total electric rigs +137 +8 +145 +Mechanical rigs +171 +12 +183 +Total +308 +20 +328 +We estimate the depth capacity with respect to our marketable rigs as of December 31, 2011 to be as +follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +5,250 to 7,999 +— +3 +3 +8,000 to 11,999 +31 +9 +40 +12,000 to 15,999 +175 +8 +183 +16,000 to 25,000 +102 +— +102 +Total +308 +20 +328 +At December 31, 2011, we owned and operated 326 trucks and 403 trailers used to rig down, transport +and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations in periods of high drilling rig utilization. +We perform repair and overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, +Colorado, Pennsylvania and western Canada. +Pressure Pumping Operations +General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the +Appalachian Basin (Northeast Region). Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require +well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation +services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing. +Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered +into for a specified +6 +Table of Contents +period of time and may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other +items. We believe that our pressure pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each pressure pumping contract contains the actual +terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions or other factors. +Equipment — We have pressure pumping equipment used in providing hydraulic and nitrogen fracturing services as well as +nitrogen, cementing and acid pumping services, with a total of approximately 631,000 hydraulic horsepower as of December 31, 2011. Pressure pumping equipment at December 31, 2011 included: +Quintiplex +Fracturing +Equipment +Triplex +Fracturing +Equipment +Other +Pumping +Equipment +Total +Southwest Region: +Number of units +107 +22 +21 +150 +Approximate hydraulic horsepower +250,750 +37,750 +20,270 +308,770 +Northeast Region: +Number of units +76 +69 +109 +254 +Approximate hydraulic horsepower +171,000 +90,000 +61,300 +322,300 +Combined: +Number of units +183 +91 +130 +404 +Approximate hydraulic horsepower +421,750 +127,750 +81,570 +631,070 +Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, +manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite. +Materials — Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, +from time to time. We purchase these materials from various suppliers. These purchases are made in the spot market or pursuant to other arrangements, that do not cover all of our required supply and that sometimes require us to purchase the supply +or pay liquidated damages if we do not purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for +continued provision of any particular material or should one of our suppliers fail to deliver or timely deliver our materials. +Oil and +Natural Gas Interests +We own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil +and natural gas working interests are located primarily in producing regions of Texas and New Mexico. Our oil and natural gas assets constituted less than 1% of our consolidated assets as of December 31, 2011. +Customers +The customers +of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2011, no single customer accounted for 10% or more +of our consolidated operating revenues. +Competition +Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand. The price for our services is a key +competitive factor, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications +7 +Table of Contents +of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for land drilling and pressure +pumping services will continue to be highly competitive. +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, +• +the relationships with our employees, +• +containment and disposal of hazardous materials, oilfield waste, other waste materials and acids, +• +use of underground storage tanks, +• +use of underground injection wells, and +• +hydraulic fracturing and related activities. +To date, applicable environmental laws and regulations in the United States and Canada have not required the expenditure of significant resources outside the ordinary course of business. We do not +anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any +new requirements could become material, and we could incur liability in any instance of noncompliance. +Our business is +generally affected by political developments and by federal, state, foreign, and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for +economic, environmental and other policy reasons could increase costs relating to drilling and production, and otherwise have an adverse effect on our operations. Federal, state, foreign and local environmental laws and regulations currently apply +to our operations and may become more stringent in the future. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a federal, state, foreign or local governmental authority, could have a material adverse +effect on our business, financial condition and results of operation. +We believe 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 operated by us or our predecessors, which may have resulted, or may result, in soil +and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under federal, state, foreign and local laws and regulations. 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. We could be required to remove or +remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator. +Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, +but the discussion does not cover all environmental laws and regulations that govern our operations. +In the United States, 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. +8 +Table of Contents +The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and +comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production +wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of +materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination. +The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern: +• +the prevention of discharges, including oil and produced water spills, and +• +liability for drainage into waters. +The Oil Pollution Act 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. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages +recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages. +Our activities +include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential impacts of hydraulic fracturing on +groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such +efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers. See “Item 1A. Risk +Factors — Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Result in Operational Delays.” +In Canada, a variety of Canadian federal, provincial and municipal laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, +use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and +other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and +approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. +Our operations are also subject to federal, state, foreign and local laws, rules and regulations for the control of air emissions, +including the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining +operating permits and approvals for air emissions. For example, in July 2011, the U.S. Environmental Protection Agency (“EPA”) published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for +Hazardous Air Pollutants (“NESHAP”) that would impose, among other things, new standards for completions of hydraulically fractured natural gas wells. For more information, please refer to our discussion under “Item 1A. Risk Factors +— We Are Subject to Compliance with +9 +Table of Contents +Stringent Environmental Laws and Regulations That May Expose Us to Significant Costs and Liabilities, and Future Regulations May Be More Stringent.” +We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) +emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of +Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate +actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. See “Item 1A. Risk Factors — Legislation and Regulation of Greenhouse +Gases Could Adversely Affect Our Business.” +Risks and Insurance +Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, +blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property. Our operations could also cause significant +environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, +our drilling and pressure pumping contracts typically contain contractual rights to indemnity from our customer for, among other things, reservoir and certain pollution damage. Our contractual right to indemnification, however, may be unenforceable +or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their contractual indemnification obligations to us due to financial, legal or other reasons. +Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial +condition, cash flows and results of operations. +We maintain insurance coverage of types and amounts that we believe to be +customary for our businesses, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other +risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any +insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our +drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. +For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self insured retention on our general liability insurance coverage. We +self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. If a significant accident or other event occurs and is not +fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our +operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be +available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such +10 +Table of Contents +insurance prohibitive or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims +for insurance coverage. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors — Our Operations +Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May +Not Fully Protect Us.” +Employees +We had approximately 8,200 full-time employees at December 31, 2011. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee +relations to be satisfactory. None of our employees are represented by a union. +Seasonality +Seasonality has not significantly affected our overall operations, however the winter weather in the Appalachian Basin has recently +resulted in slower activity for our pressure pumping operations. In addition, our drilling operations in Canada and, to a lesser extent, our pressure pumping operations in the Appalachian Basin, are subject to slow periods of activity during the +annual Spring thaw. +Raw Materials and Subcontractors +We use many suppliers of raw materials and services. Although these materials and services have historically been available, 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. \ No newline at end of file diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/item13.txt b/raw/filings/0000889900/2011/0001193125-12-052274/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..0cddff69e477bef9ebe48b2e286609648c8a086d --- /dev/null +++ b/raw/filings/0000889900/2011/0001193125-12-052274/item13.txt @@ -0,0 +1,3 @@ +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated herein by reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/item9a.txt b/raw/filings/0000889900/2011/0001193125-12-052274/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e537e981a34123d208a0bd1ed9dc527e87805767 --- /dev/null +++ b/raw/filings/0000889900/2011/0001193125-12-052274/item9a.txt @@ -0,0 +1,19 @@ +Item 9A. +Controls and Procedures. +Disclosure Controls and Procedures: +Under the supervision and with the +participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in +Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2011, our disclosure controls and procedures +were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is +accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. +Management’s Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the +participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011, based on the Internal Control-Integrated Framework +issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2011. +The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers +LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this Report. +42 +Table of Contents +Changes in Internal Control over Financial Reporting: +There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have +materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/rp_note.txt b/raw/filings/0000889900/2011/0001193125-12-052274/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2011/0001193125-12-052274/rpt_disclosure.txt b/raw/filings/0000889900/2011/0001193125-12-052274/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/filing.txt b/raw/filings/0000889900/2013/0001193125-14-054910/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..85577a34f214a8567dfd41e79d2bb539e6a738af --- /dev/null +++ b/raw/filings/0000889900/2013/0001193125-14-054910/filing.txt @@ -0,0 +1,5963 @@ +10-K +1 +d639374d10k.htm +10-K +10-K +Table of Contents +UNITED STATES SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2013 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 0-22664 +Patterson-UTI +Energy, Inc. +(Exact name of registrant as specified in its charter) +Delaware +75-2504748 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +450 Gears Road, Suite 500, Houston, Texas +77067 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: +(281) 765-7100 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Exchange on Which Registered +Common Stock, $0.01 Par Value +The Nasdaq Global Select Market +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ or No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ or No þ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for +such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 +days. Yes þ No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ or No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in +definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller +reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer þ +Accelerated filer ¨ +Non-accelerated filer ¨ +Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). +Yes ¨ No þ +The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 28, 2013, the last business day of the registrant’s most recently +completed second fiscal quarter, was approximately $2.8 billion, calculated by reference to the closing price of $19.36 for the common stock on the Nasdaq Global Select Market on that date. +As of February 7, 2014, the registrant had outstanding 144,233,121 shares of common stock, $0.01 par value, its only class of common +stock. +Documents incorporated by reference: +Portions of the registrant’s definitive proxy statement for the 2014 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. +Table of Contents +DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking +statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, +as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of +operations; oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; competition; equipment +availability; government regulation; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “believes,” +“budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or +“anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical +trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no +assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations +included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act. +Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ +materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, volatility in customer spending and in oil +and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, global economic conditions, excess availability of land drilling rigs and +pressure pumping equipment, including as a result of reactivation or construction, equipment specialization and new technologies, adverse industry conditions, adverse credit and equity market conditions, difficulty in building and deploying new +equipment and integrating acquisitions, shortages, delays in delivery and interruptions in supply of equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full +indemnification or insurance, ability to effectively identify and enter new markets, governmental regulation, ability to realize backlog, ability to retain management and field personnel and other factors. Refer to “Risk Factors” contained +in Item 1A of this Report for a more complete discussion of factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking +statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes +in internal estimates or otherwise, except as required by law. +PART I +Item 1. +Business +Available Information +This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website ( www.patenergy.com ) as soon as reasonably practicable after we electronically file such material with, or furnish it to, +the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, +Washington, DC 20549. +1 +Table of Contents +You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site ( www.sec.gov ) that contains reports, proxy +and information statements and other information regarding issuers that file electronically with the SEC. +Overview +We own and operate one of the largest fleets of land-based drilling rigs in the United States. The Company was formed in 1978 and +reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates in the continental United States, Alaska, and western and northern Canada. +As of December 31, 2013, we had a drilling fleet that consisted of 279 marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a +drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without significant capital expenditures. We also have a substantial +inventory of drill pipe and drilling rig components that support our ongoing drilling operations. +We provide pressure pumping +services to oil and natural gas operators primarily in Texas and the Appalachian region. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. +We also own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests +are located primarily in Texas and New Mexico. +On October 1, 2010, we acquired the assets and operations of a pressure +pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on January 27, 2011. The results of our electric wireline business are +presented as discontinued operations in this Report. +Industry Segments +Our revenues, operating profits and identifiable assets are primarily attributable to three industry segments: +• +contract drilling services, +• +pressure pumping services, and +• +oil and natural gas exploration and production. +All of our industry segments had operating profits in 2013, 2012 and 2011. +See +“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 14 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial +information pertaining to these industry segments. +Contract Drilling Operations +General — We market our contract drilling services to major and independent oil and natural gas operators. As of +December 31, 2013, we had 279 marketable land-based drilling rigs based in the following regions: +• +70 in west Texas and southeastern New Mexico, +• +25 in north central and east Texas, northern Louisiana and eastern Oklahoma, +• +47 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana, North Dakota and Alaska), +• +55 in south Texas, +• +32 in the Texas panhandle and western Oklahoma, +• +36 in the Appalachian region (Pennsylvania, Ohio and West Virginia) and +• +14 in western and northern Canada. +2 +Table of Contents +Our marketable drilling rigs have rated maximum depth capabilities ranging from 8,000 feet +to 25,000 feet. Of these drilling rigs, 180 are electric rigs and 99 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the power from its engines (the sole energy source for a mechanical rig) into +electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs. +Drilling rigs are typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe +and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is +competitive. We have spent over $2.0 billion during the last three years on capital expenditures to (1) build new land drilling rigs and (2) modify, upgrade and extend the lives of components of our drilling fleet. During fiscal years +2013, 2012 and 2011, we spent approximately $505 million, $745 million and $785 million, respectively, on these capital expenditures. +Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job. +Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, +fuel and other materials and qualified personnel. Some of these have been in short supply from time to time. +Drilling +Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term +in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently six months to three years) and provide for the use of the drilling rig to drill multiple wells. During +2013, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 20 days. +Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our drilling personnel and necessary maintenance expenses. Most drilling +contracts are subject to termination by the customer on short notice and may or may not contain provisions for an early termination payment to us in the event that the contract is terminated by the customer. We believe that our drilling contracts +generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each drilling contract contains the actual terms setting forth our rights and obligations and those of the +customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors. +Our drilling 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 job 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. +Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our +compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions +or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. All of the wells we drilled in 2013, 2012 and 2011 were under daywork contracts. +Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The +customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed-upon depth. If we drill the well in +less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth +than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling +3 +Table of Contents +contractor typically assumes certain risks associated with loss of the well from fire, blowouts and other risks. Although we have entered into footage contracts in the past, we did not drill any +wells under footage contracts in the past three years. +Under turnkey contracts, we contract to drill a well to a certain depth +under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are +required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, +blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed-upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a +turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey +contract, however, profits can be significantly reduced and losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of +drilling contracts. Although we have entered into turnkey contracts in the past, we did not drill any wells under turnkey contracts in the past three years. +Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows: +Year Ended December 31, +2013 +2012 +2011 +Average rigs operating per day(1) +192 +221 +216 +Number of rigs operated during the year +235 +267 +250 +Number of wells drilled during the year +3,378 +3,587 +3,529 +Number of operating days +69,918 +80,833 +78,758 +(1) +A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. +Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to +match the needs of our customers. While conventional wells remain an important source of natural gas and oil, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for natural gas and +oil in North America. +To address our customers’ needs for drilling horizontal wells in shale and +other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling fleet. We have delivered new APEX ® rigs to the market and have made performance and safety improvements to existing high capacity rigs. APEX 1500 ® rigs are 1,500 horsepower electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other highly automated +pipe handling equipment. APEX 1000 ® rigs are 1,000 horsepower electric rigs with advanced technology equipment +similar to the APEX 1500 ® rigs, but with a more compact design to fit on smaller locations. APEX WALKING ® rigs are designed to efficiently drill multiple wells from a single pad, by “walking” between the +wellbores without requiring time to lower the mast and lay down the drill pipe. Many APEX 1500 ® and APEX 1000 ® rigs have also been equipped +4 +Table of Contents +with walking systems as noted below. As of December 31, 2013 our drilling fleet was comprised of the following: +Number of Rigs +Classification +U.S. +Canada +Total +APEX +1500 ® rigs (including 19 with walking systems) +60 +— +60 +APEX +1000 ® rigs (including nine with walking systems) +15 +— +15 +APEX +WALKING ® rigs +49 +— +49 +Other electric rigs (including two with walking systems) +48 +8 +56 +Total electric rigs +172 +8 +180 +Mechanical rigs +93 +6 +99 +Total +265 +14 +279 +We estimate the depth capacity with respect to our marketable rigs as of December 31, 2013 to be as +follows: +Number of Rigs +Depth Rating (Ft.) +U.S. +Canada +Total +8,000 to 12,999 +9 +6 +15 +13,000 to 14,999 +37 +4 +41 +15,000 to 17,999 +86 +4 +90 +18,000 to 25,000 +133 +— +133 +Total +265 +14 +279 +At December 31, 2013, we owned and operated 298 trucks and 398 trailers used to rig down, transport +and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations in periods of high drilling rig utilization. +We perform repair and/or overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, +Wyoming, Colorado, North Dakota, Pennsylvania and western Canada. +Pressure Pumping Operations +General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the +Appalachian region (Northeast Region). Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require +well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation +services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing. +Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered +into for a specified period of time and may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other items. We believe that our pressure +pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each pressure pumping contract contains the actual terms setting forth our rights and +obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors. +5 +Table of Contents +Equipment — We have pressure pumping equipment used in providing hydraulic and +nitrogen fracturing services as well as nitrogen, cementing and acid pumping services, with a total of approximately 763,000 hydraulic horsepower as of December 31, 2013. Pressure pumping equipment at December 31, 2013 included: +Hydraulic +Fracturing +Equipment +Other +Pumping +Equipment +Total +Southwest Region: +Number of units +146 +27 +173 +Approximate hydraulic horsepower +342,850 +27,550 +370,400 +Northeast Region: +Number of units +172 +105 +277 +Approximate hydraulic horsepower +332,050 +60,600 +392,650 +Combined: +Number of units +318 +132 +450 +Approximate hydraulic horsepower +674,900 +88,150 +763,050 +Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, +manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite. +Materials — Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, +from time to time. We purchase these materials from various suppliers. These purchases are made in the spot market or pursuant to other arrangements that do not cover all of our required supply and that sometimes require us to purchase the supply or +pay liquidated damages if we do not purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for +delivery of any particular material or should one of our suppliers fail to timely deliver our materials. +Oil and Natural Gas Interests +We own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working +interests are located primarily in producing regions of Texas and New Mexico. Our oil and natural gas assets constituted approximately 1% of our consolidated assets as of December 31, 2013. +Customers +The customers +of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2013, one customer accounted for approximately +$286 million or 10.5% of our consolidated operating revenues. These revenues were earned in both our contract drilling and pressure pumping businesses. +Competition +Our contract drilling and pressure pumping businesses are +highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand. The price for our services is a key competitive factor, in part because equipment used in our businesses can be moved from one area to +another in response to market conditions. In addition to price, we believe availability, condition and technical specifications of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is +awarded a job. We expect that the market for land drilling and pressure pumping services will continue to be highly competitive. +6 +Table of Contents +Government and Environmental Regulation +All of our operations and facilities are subject to numerous federal, state, foreign, regional and local laws, rules and regulations +related to various aspects of our business, including: +• +drilling of oil and natural gas wells, +• +hydraulic fracturing, cementing, nitrogen and acidizing and related well servicing activities, +• +containment and disposal of hazardous materials, oilfield waste, other waste materials and acids, +• +use of underground storage tanks and injection wells, and +• +our employees. +To date, applicable environmental laws and regulations in the places in which we operate have not required the expenditure of significant resources outside the ordinary course of business. We do not +anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any +new requirements could become material, and we could incur liability in any instance of noncompliance. +Our business is +generally affected by political developments and by federal, state, foreign, regional and local laws, rules and regulations that relate to the oil and natural gas industry. The adoption of laws, rules and regulations affecting the oil and natural +gas industry for economic, environmental and other policy reasons could increase costs relating to drilling, completion and production, and otherwise have an adverse effect on our operations. Federal, state, foreign, regional and local environmental +laws, rules and regulations currently apply to our operations and may become more stringent in the future. Any suspension or moratorium of the services we or others provide, whether or not short-term in nature, by a federal, state, foreign, regional +or local governmental authority, could have a material adverse effect on our business, financial condition and results of operation. +We believe 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 operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to +remediation requirements under federal, state, foreign, regional and local laws, rules and regulations. 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. We could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held +responsible for oil and natural gas properties in which we own an interest but are not the operator. +Some of the environmental +laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations. +In the United States, 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, including prior owners and operators who are no longer active at a site; 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 and implementing +regulations govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from +regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials +(including materials disposed of +7 +Table of Contents +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, into jurisdictional waters; and +• +liability for drainage into such waters. +The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into jurisdictional 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. Failure to comply with ongoing +requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages +recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages. +Our activities +include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shale and other unconventional formations. Due to concerns raised relating to potential impacts +of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the +activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers. +See “Item 1A. Risk Factors — Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Limit or Delay Our Operations.” +In Canada, a variety of Canadian federal, provincial and municipal laws, rules and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, +handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws, rules and regulations also require that +facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the +submission and approval of environmental assessments or permit applications. These laws, rules and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the +environment. +Our operations are also subject to federal, state, foreign, regional and local laws, rules and regulations for +the control of air emissions, including those associated with the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in the future for air pollution control +equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For more information, please refer to our discussion under “Item 1A. Risk Factors — Environmental and Occupational Health and Safety +Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.” +We are +aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the +Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in +the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. +8 +Table of Contents +Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. See “Item 1A. Risk Factors — Legislation +and Regulation of Greenhouse Gases Could Adversely Affect Our Business.” +Risks and Insurance +Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, +blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir +damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, +our drilling and pressure pumping contracts typically contain provisions requiring our customer to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited +due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be +unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows +and results of operations. +We maintain insurance coverage of types and amounts that we believe to be customary in the +industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss +to our rigs and certain other assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will +be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and certain +other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we +generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability and automobile liability insurance +coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. +Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our +operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be +available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive or that our coverage will cover a +specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. +If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our +business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors – Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant +Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.” +9 +Table of Contents +Employees +We had approximately 7,800 full-time employees at December 31, 2013. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee +relations to be satisfactory. None of our employees are represented by a union. +Seasonality +Seasonality has not significantly affected our overall operations. However, our drilling operations in Canada are subject to slow periods +of activity during the annual spring thaw. Additionally, toward the end of some years, we experience slower activity in our pressure pumping operations in connection with the holidays and as customers’ capital expenditure budgets are depleted. +Raw Materials and Subcontractors +We use many suppliers of raw materials and services. Although these materials and services have historically been available, 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. +Item 1A. +Risk Factors. +You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us +or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the +other information set forth in this Report, including our consolidated financial statements and the related notes. +We +Are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results. +We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and +produce oil and natural gas in North America. If these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous +factors over which we have no control, such as: +• +the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage, +• +the prices, and expectations about future prices, of oil and natural gas, +• +the supply of and demand for drilling and pressure pumping equipment, +• +the cost of exploring for, developing, producing and delivering oil and natural gas, +• +the environmental and other laws and governmental regulations regarding the exploration, development, production and delivery of oil and natural gas, +and in particular, public pressure on, and legislative and regulatory interest within, federal, state, foreign, regional and local governments to stop, significantly limit or regulate drilling and pressure pumping activities, including hydraulic +fracturing, and +• +merger and divestiture activity among oil and natural gas producers. +In particular, our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and +expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as: +• +market supply and demand, +• +domestic and international military, political, economic and weather conditions, +10 +Table of Contents +• +the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets, +• +technical advances affecting energy consumption and production, and +• +the price and availability of alternative fuels. +All of these factors are beyond our control. Declines in the market prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of +2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and +natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information +Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below +$2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural +gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. Our average number of rigs operating remains +well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling +activity and excess capacity, our average number of rigs operating has declined from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of +capital. Low market prices for oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of +high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for +our drilling rigs and pressure pumping services. +Global Economic Conditions May Adversely Affect Our Operating Results. +Global economic conditions and volatility in commodity prices may cause our customers to reduce or curtail their +drilling and well completion programs, which could result in a decrease in demand for our services. In addition, uncertainty in the capital markets may result in reduced access to financing by our customers and reduced demand for our services. +Furthermore, these factors may result in certain of our customers experiencing an inability to pay suppliers, including us. The global economic environment in the past has experienced significant deterioration in a relatively short period, and there +is no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash +flows and results of operations. +A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and +Excess Pressure Pumping Equipment May Adversely Affect Our Utilization and Profit Margins. +The North American oil and +natural gas services industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, +drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. +In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology +drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could +11 +Table of Contents +continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include: +• +movement of drilling rigs from region to region, +• +reactivation of land-based drilling rigs, or +• +construction of new technology drilling rigs. +Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has +resulted in excess capacity of conventional drilling rigs. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services and there has been a significant increase in the +construction of new pressure pumping equipment across the industry. As a result of low natural gas prices and the construction of new equipment, there is currently an excess of pressure pumping equipment available. In circumstances of excess +capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict the future level of demand for our contract drilling or pressure pumping services or future +conditions in the oil and natural gas contract drilling or pressure pumping businesses. +Shortages, Delays in Delivery +and Interruptions in Supply of Drill Pipe, Replacement Parts, Other Equipment, Supplies and Materials Adversely Affect Our Operating Results. +During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages of drill pipe, replacement parts, other equipment, supplies and materials, including, +in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In +addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons: +• +weather issues, whether short-term such as a hurricane, or long-term such as a drought, and +• +a shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of +vendors to other customers or third parties. +These price increases, delays in delivery and interruptions in +supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our drilling rigs and pressure +pumping equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured +Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us. +Our operations are +subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution, exposure and reservoir damage. These hazards could cause personal injury +or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss +of oil and natural gas production, pollution and other environmental damages. +We have indemnification agreements with many of +our customers, and we also maintain liability and other forms of insurance. In general, our drilling and pressure pumping contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain +pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their indemnification +obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully +12 +Table of Contents +indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations. +We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against +all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and certain other assets, +employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or +liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and certain other assets, such insurance does not +cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a $1.0 million per +occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability and automobile liability insurance coverage. We self-insure a number of other +risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. +Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits and exclusions. As +a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that +insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or +such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for which we are not fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of +operations. +If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or +recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. +New Technologies May Cause Our Operating Methods and Equipment to Become Less Competitive, and Higher Levels of Capital Expenditures May be Necessary to Remain Competitive in our Industry. +The market for our services is characterized by continual technological and process developments that have resulted +in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers are increasingly demanding the services of newer, higher specification drilling rigs. Accordingly, a higher +level of capital expenditures may be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers. In addition, +technological changes, process improvements and other factors that increase operational efficiencies could result in oil and natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days. +Technological and process developments in the pressure pumping business could have similar effects. +In recent years, we have +added drilling rigs to our fleet through new construction, and we have purchased new pressure pumping equipment. Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements +in competitors’ equipment could make our equipment less competitive. +If we are not successful in building new rigs and +pressure pumping equipment or upgrading our existing rigs and pressure pumping equipment in a timely and cost-effective manner, we could lose market share. New technologies, services or standards could render some of our services, drilling rigs or +pressure pumping equipment obsolete, which could have a material adverse impact on our business, financial condition, cash flows and results of operation. +13 +Table of Contents +Our Current Backlog of Contract Drilling Revenue May Not Ultimately Be Realized as +Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment. +As of +December 31, 2013, our contract drilling backlog for future revenues under term contracts, which we define as contracts with a fixed term of six months or more, was approximately $946 million. Fixed-term drilling contracts customarily provide +for termination at the election of the customer, with an “early termination payment” to us if a contract is terminated prior to the expiration of the fixed term. However, in certain circumstances, for example, destruction of a drilling rig +that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us. Additionally, during depressed market conditions or +otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate, renegotiate or fail to honor their contractual obligations. In addition, we may not be able to perform under these contracts due to events beyond +our control, and our customers may seek to cancel or negotiate our contracts for various reasons, including those described above. As a result, we may be unable to realize all of our current contract drilling backlog. In addition, the renegotiation +or termination of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, cash flows and results of operations. +The Oil Service Business Sectors in Which We Operate Are Highly Competitive with Excess Capacity, which Adversely Affects Our +Operating Results. +The land drilling and pressure pumping businesses are highly competitive. At 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 ability to move drilling rigs and pressure pumping +equipment 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 to be intense due to the existence of available rigs and pressure pumping equipment. As a result of competition, our utilization may decrease and/or we may be unable to +maintain or increase prices for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Reliance on Management, Competition for Experienced Personnel and Rising Labor Costs Adversely Affect Our Operating Results. +We greatly depend on the efforts of our key employees to manage our operations. The loss of members of management could have a material +adverse effect on our business. In addition, we utilize highly skilled personnel in operating and supporting our businesses. In times of increasing demand for our services, it may be difficult to attract and retain qualified personnel. During +periods of high demand for our services, wage rates for operations personnel are also likely to increase, resulting in higher operating costs. An inability to obtain or attract and retain qualified personnel and increases in wage rates could have a +material adverse effect on our business, financial condition, cash flows and results of operations. +The Loss of Large +Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations. +In 2013, we +received approximately 46% of our consolidated operating revenues from our ten largest customers and approximately 29% of our consolidated operating revenues from our five largest customers. During 2013, one customer accounted for approximately $286 +million or 10.5% of our consolidated operating revenues. These revenues were earned in both our contract drilling and pressure pumping businesses. The loss of one or more of our larger customers could have a material adverse effect on our business, +financial condition, cash flows and results of operations. +14 +Table of Contents +Growth Through the Building of New Rigs and Pressure Pumping Equipment and Rig and +Other Acquisitions Are Not Assured. +We have increased our drilling rig fleet and pressure pumping horsepower in the +past through mergers, acquisitions and new construction. There can be no assurance that acquisition opportunities will be available in the future or that we will be able to execute timely or efficiently any plans for building new rigs and pressure +pumping equipment. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, contract +drillers may continue to build new, high technology rigs and providers of pressure pumping services may continue to build new, high horsepower equipment. +There can be no assurance that we will: +• +have sufficient capital resources to complete additional acquisitions or build new rigs or pressure pumping equipment, +• +successfully integrate additional drilling rigs, pressure pumping equipment or other assets or businesses, +• +effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping equipment, +• +successfully deploy idle, stacked or additional rigs and pressure pumping equipment, +• +maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment, or +• +successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition or the building of +new drilling rigs and pressure pumping equipment. +We may incur substantial indebtedness to finance future +acquisitions, build new drilling rigs or build new pressure pumping equipment and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a +significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, continued growth could strain our management, operations, +employees and other resources. +Environmental and Occupational Health and Safety Laws and Regulations, Including +Violations Thereof Could Materially Adversely Affect Our Operating Results. +Our business is subject to numerous +federal, state, foreign, regional and local laws, rules and regulations governing the discharge of substances into the environment, protection of the environment and worker health and safety, including, without limitation, laws concerning the +containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be +substantial. A failure to comply with these requirements could expose us to: +• +substantial civil, criminal and/or administrative penalties, +• +modification, denial or revocation of permits or other authorizations, +• +imposition of limitations on our operations, and +• +performance of site investigatory, remedial or other corrective actions. +In addition, environmental laws and regulations in the countries in which we operate impose a variety of requirements on “responsible +parties” related to the prevention of spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and pressure pumping equipment, we may be deemed to be a responsible party under these laws and +regulations. +Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more +stringent over time. Stricter laws, regulations or enforcement policies could significantly increase +15 +Table of Contents +compliance costs for us and our customers and have a material adverse effect on our operations or financial position. For example, on August 16, 2012, the EPA issued final rules that +establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including NSPS to address emissions of sulfur dioxide and volatile organic compounds and NESHAPS to address hazardous air +pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions +or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are now required to use completion combustion device equipment (i.e., flaring) if emissions cannot be +directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and +modifications to the leak detection standards for valves. These rules may require the implementation of new operating standards which may impact our business. If these or other initiatives result in an increase in regulation, it could increase costs +to us and our customers or reduce demand for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. +Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Limit or Delay Our Operations. +Members of the U.S. Congress and the EPA are reviewing more stringent regulation of hydraulic fracturing, a technology +employed by our pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the EPA and the U.S. Congress are studying whether there is +any link between hydraulic fracturing activities and soil or ground water contamination. As part of their respective studies, the House Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our +company, for information on their hydraulic fracturing practices. We have responded to each of the inquiries. In addition, legislation has been proposed in the U.S. Congress to amend the Federal Safe Drinking Water Act to require the disclosure of +chemicals used by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in +the fracturing process are impairing ground water or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could limit or delay operational activities or increase +operating costs and could result in additional regulatory burdens that could make it more difficult to perform or limit hydraulic fracturing and increase our costs of compliance and doing business. Certain states where we operate, including Texas, +have adopted or are considering similar disclosure legislation. For example, Colorado, North Dakota, Montana, Texas, Louisiana, and Wyoming have adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can +be performed and requiring various degrees of chemical disclosure. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection +Control Program and is developing final guidance documents related to this newly asserted regulatory authority. Additional regulation could increase the costs of conducting our business and could materially reduce our business opportunities and +revenues if our customers decrease their levels of activity in response to such regulation. +A number of federal agencies are +analyzing, or have been requested to review a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and +groundwater. The EPA released a progress report on December 21, 2012 outlining work currently underway and is expected to release a draft final report in 2014. In addition, the EPA announced on October 20, 2011 that it is launching a study +of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations in 2014. These ongoing or proposed studies, depending on their course, and any meaningful results obtained, could spur initiatives +to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism. +16 +Table of Contents +The adoption of any future federal, state, foreign, regional or local laws that impact +permitting requirements for, result in reporting obligations on, or otherwise limit, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing and could increase our costs of compliance and doing business and +reduce demand for our services. Regulation that significantly restricts or prohibits hydraulic fracturing could have a material adverse impact on our business, financial condition, cash flows and results of operations. +Legislation and Regulation of Greenhouse Gases Could Adversely Affect Our Business +We are aware of the increasing focus of local, state, regional, national and international regulatory bodies on greenhouse gas +(“GHG”) emissions and climate change issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the United States and internationally, +regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries to meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be +costly and difficult to implement. The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis. Further, following a finding by the EPA that certain GHGs represent an endangerment +to human health, the EPA finalized a rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s New Source Review Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule +“tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Several states and geographic regions in the United States have +also adopted legislation and regulations to reduce emissions of GHGs. Additional legislation or regulation by these states and regions, the EPA, and/or any international agreements to which the United States may become a party, that control or limit +GHG emissions or otherwise seek to address climate change could adversely affect our operations. The cost of complying with any new law, regulation or treaty will depend on the details of the particular program. We will continue to monitor and +assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting +these requirements may adversely affect our business, results of operations and financial condition. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs +and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. +Legal Proceedings Could Have a Negative Impact on our Business. +The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. Lawsuits or claims +against us could have a material adverse effect on our business, financial condition and results of operations. Any legal proceedings or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the +public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. +International Uncertainties, and Laws Related to International Opportunities Could Adversely Affect our Opportunities and Future +Business. +We currently conduct operations in Canada, and we have incurred selling, general and administrative expenses +related to the evaluation of and preparation for other international opportunities. International operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social +unrest, strikes, terrorism, kidnapping of employees, nationalization, forced negotiation or modification of contracts, expropriation of equipment as well as expropriation of a particular oil company operator’s property and drilling rights, +taxation policies, foreign exchange restrictions, currency rate fluctuations and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. +To the extent we evaluate and prepare for international opportunities and conduct any international operations, there can be no assurance +that there will not be changes in local laws, regulations and administrative +17 +Table of Contents +requirements or the interpretation thereof which could have a material adverse effect on the cost of entry into international markets, the profitability of international operations or the ability +to continue those operations in certain areas. Because of the impact of local laws, our future international operations, if any, in certain areas may be conducted through entities in which local citizens own interests and through entities (including +joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements +would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find +acceptable. +There can be no assurance that we will: +• +identify attractive opportunities in international markets, +• +have sufficient capital resources to pursue and consummate international opportunities, +• +successfully integrate international drilling rigs, pressure pumping equipment or other assets or businesses, +• +effectively manage the start-up, development and growth of an international organization and assets, +• +hire, attract and retain the personnel necessary to successfully conduct international operations, or +• +successfully improve our financial condition, results of operations, business or prospects as a result of the entry into one or more international +markets. +In addition, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery +laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. Some of the parts of the world where contract drilling and +pressure pumping activities are conducted have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practice and could impact business. Any +failure to comply with the FCPA or other anti-bribery legislation could subject to us to civil, criminal and/or administrative penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results +of operation. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure +of drilling rigs, pressure pumping equipment or other assets. +We may incur substantial indebtedness to finance an +international transaction or operations and also may issue equity, convertible or debt securities in connection with any such transactions or operations. Debt service requirements could represent a significant burden on our results of operations and +financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, international expansion could strain our management, operations, employees and other resources. +Our Business Is Subject to Cybersecurity Risks and Threats. +Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. It is +possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, disruption of our and +customers’ business operations and safety procedures, loss or damage to our worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events. +We Are Dependent Upon Our Subsidiaries to Meet our Obligations Under Our Long Term Debt +We have borrowings outstanding under our senior notes, term loan facility and, from time to time, revolving credit facility. These +obligations are guaranteed by each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends +18 +Table of Contents +paid to us by our subsidiaries. If our subsidiaries do not generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal payment obligations. +Variable Rate Indebtedness Subjects Us to Interest Rate Risk, Which Could Cause Our Debt Service Obligations to Increase +Significantly. +We have in place a committed senior unsecured credit facility that includes a revolving credit facility +and a term loan facility. Interest is paid on the outstanding principal amount of borrowings under the credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the +margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2013, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2013, we had no +borrowings outstanding under our revolving credit facility and $92.5 million outstanding under our term credit facility at an interest rate of 2.50%. A one percent increase in the interest rate on the borrowings outstanding under our term credit +facility as of December 31, 2013 would increase our annual cash interest expense by approximately $900,000. Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts +borrowed. +Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and +Thereby Affect the Related Purchase Price. +We are a Delaware corporation subject to the Delaware General Corporation +Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors 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. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws +impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential +acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market +prices pursuant to any such transactions. +Item 1B. +Unresolved Staff Comments. +None. +Item 2. +Properties +Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment. We own substantially all of the equipment used in our businesses. +Our corporate headquarters is in leased office space and is located at 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at +that address is (281) 765-7100. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000 square feet of office and storage space. +Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout +our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada. +Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our +areas of operations, including Texas, Pennsylvania, Ohio, West Virginia and Kentucky. +Oil and Natural Gas Working +Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico. +We own our +administrative offices 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. +19 +Table of Contents +We incorporate by reference in response to this item the information set forth in +Item 1 of this Report and the information set forth in Note 3 of the Notes to Consolidated Financial Statements included in Item 8 of this Report. +Item 3. +Legal Proceedings. +In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the +Company tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and +retaliation. The Company and the EEOC are engaged in the statutory conciliation process. If such conciliation process is unsuccessful, the Company believes that litigation will ensue. The Company intends to defend itself vigorously and, +based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no +assurance as to the ultimate outcome of this matter. +Other than the matter described above, we are party to various legal +proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial +condition. +Item 4. +Mine Safety Disclosure. +Not applicable. +20 +Table of Contents +PART II +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +(a) +Market Information +Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol +“PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated: +High +Low +2012: +First quarter +$ +22.14 +$ +16.83 +Second quarter +17.70 +12.81 +Third quarter +17.75 +13.40 +Fourth quarter +19.21 +14.95 +2013: +First quarter +$ +25.48 +$ +18.59 +Second quarter +25.12 +18.96 +Third quarter +22.41 +18.83 +Fourth quarter +26.09 +21.29 +(b) +Holders +As of +February 7, 2014, there were approximately 1,100 holders of record of our common stock. +(c) +Dividends +We paid +cash dividends during the years ended December 31, 2012 and 2013 as follows: +Per Share +Total +(in thousands) +2012: +Paid on March 30, 2012 +$ +0.05 +$ +7,788 +Paid on June 29, 2012 +0.05 +7,650 +Paid on September 28, 2012 +0.05 +7,518 +Paid on December 28, 2012 +0.05 +7,346 +Total cash dividends +$ +0.20 +$ +30,302 +2013: +Paid on March 29, 2013 +$ +0.05 +$ +7,312 +Paid on June 28, 2013 +0.05 +7,361 +Paid on September 30, 2013 +0.05 +7,231 +Paid on December 31, 2013 +0.05 +7,208 +Total cash dividends +$ +0.20 +$ +29,112 +On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the +amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon +business conditions, results of operations, financial condition, terms of our credit facilities and other factors. +21 +Table of Contents +(e) +Issuer Purchases of Equity Securities +The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2013. +Period Covered +Total +Number of +Shares +Purchased +Average Price +Paid +per +Share +Total Number +of +Shares (or Units) +Purchased as Part +of Publicly +Announced Plans +or Programs +Approximate Dollar +Value of +Shares +That May Yet Be +Purchased Under the +Plans or +Programs (in +thousands)(1) +October 2013(2) +4,459 +$ +23.15 +896 +$ +187,483 +November 2013 +— +$ +— +— +$ +187,483 +December 2013 +— +$ +— +— +$ +187,483 +Total +4,459 +$ +23.15 +896 +$ +187,483 +(1) +On September 6, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in +open market or privately negotiated transactions. +(2) +We withheld 3,563 shares in October 2013 with respect to employees’ tax withholding obligations upon the vesting of restricted shares. The price used to determine +the number of shares withheld was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and +not pursuant to the stock buyback program. +22 +Table of Contents +(e) +Performance Graph +The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2008 through +December 31, 2013, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of +Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Energy Services Corp. and Precision Drilling Corp. All of the companies in our peer group are providers of land-based drilling services. Nabors Industries, Ltd. also is a provider of +pressure pumping services. The graph assumes investment of $100 on December 31, 2008 and reinvestment of all dividends. +Fiscal Year Ended December 31, +Company/Index +2008 +($) +2009 +($) +2010 +($) +2011 +($) +2012 +($) +2013 +($) +Patterson-UTI Energy, Inc. +100.00 +135.50 +192.50 +179.97 +169.86 +232.96 +Peer Group Index +100.00 +161.96 +188.47 +182.58 +161.04 +215.29 +S&P 500 Stock Index +100.00 +126.46 +145.51 +148.59 +172.37 +228.19 +Oilfield Service Index +100.00 +162.11 +205.75 +184.05 +189.89 +246.06 +S&P MidCap Index +100.00 +137.38 +173.98 +170.96 +201.53 +269.04 +The foregoing graph is based on historical data and is not necessarily indicative of future performance. +This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act. +23 +Table of Contents +Item 6. +Selected Financial Data. +Our selected consolidated financial data as of December 31, 2013, 2012, 2011, 2010 and 2009, and for each of the five years in the period ended December 31, 2013 should be read in conjunction +with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Due to the sale +of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January 2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations for all +periods presented. +Years Ended December 31, +2013 +2012 +2011 +2010 +2009 +(In thousands, except per share amounts) +Statement of Operations Data: +Operating revenues: +Contract drilling +$ +1,679,611 +$ +1,821,713 +$ +1,669,581 +$ +1,081,898 +$ +599,287 +Pressure pumping +979,166 +841,771 +845,803 +350,608 +161,441 +Oil and natural gas +57,257 +59,930 +50,559 +30,425 +21,218 +Total +2,716,034 +2,723,414 +2,565,943 +1,462,931 +781,946 +Operating costs and expenses: +Contract drilling +968,754 +1,075,491 +972,778 +655,678 +357,742 +Pressure pumping +744,243 +580,878 +561,398 +235,100 +124,100 +Oil and natural gas +12,909 +11,303 +9,615 +7,020 +7,341 +Depreciation, depletion, amortization and impairment +597,469 +526,614 +437,279 +333,493 +289,847 +Selling, general and administrative +73,852 +64,473 +64,271 +53,042 +43,935 +Net (gain) loss on asset disposals +(3,384 +) +(33,806 +) +(4,999 +) +(22,812 +) +3,385 +Provision for bad debts +— +1,100 +— +(2,000 +) +3,810 +Acquisition-related expenses +— +— +— +2,485 +— +Total +2,393,843 +2,226,053 +2,040,342 +1,262,006 +830,160 +Operating income (loss) +322,191 +497,361 +525,601 +200,925 +(48,214 +) +Other expense +(25,750 +) +(21,688 +) +(14,883 +) +(10,171 +) +(3,341 +) +Income (loss) from continuing operations before income taxes +296,441 +475,673 +510,718 +190,754 +(51,555 +) +Income tax expense (benefit) +108,432 +176,196 +187,938 +72,856 +(17,595 +) +Income (loss) from continuing operations +$ +188,009 +$ +299,477 +$ +322,780 +$ +117,898 +$ +(33,960 +) +Income (loss) from continuing operations per common share: +Basic +$ +1.29 +$ +1.96 +$ +2.08 +$ +0.77 +$ +(0.22 +) +Diluted +$ +1.28 +$ +1.96 +$ +2.06 +$ +0.76 +$ +(0.22 +) +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.20 +$ +0.20 +$ +0.20 +Weighted average number of common shares outstanding: +Basic +144,356 +151,144 +153,871 +152,772 +152,069 +Diluted +145,303 +151,699 +155,304 +153,276 +152,069 +Balance Sheet Data: +Total assets +$ +4,687,127 +$ +4,556,911 +$ +4,221,901 +$ +3,423,031 +$ +2,662,152 +Borrowings under line of credit +— +— +110,000 +— +— +Other long term debt +682,500 +692,500 +382,500 +392,500 +— +Stockholders’ equity +2,755,997 +2,640,657 +2,516,631 +2,187,607 +2,081,700 +Working capital +454,373 +340,128 +346,238 +241,445 +263,511 +24 +Table of Contents +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +Management Overview — We are a leading provider of 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 pressure pumping services. In addition to these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties. +We acquired an electric wireline business on October 1, 2010 and sold the business on January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this +Report. +As of December 31, 2013, we had a drilling fleet that consisted of 279 marketable land-based drilling rigs. There +continues to be uncertainty with respect to the global economic environment, crude oil and natural gas prices are volatile and natural gas prices have been low in recent years. Activity in our drilling business decreased in the fourth quarter of +2013 compared to the fourth quarter of 2012. In the fourth quarter of 2013, our average number of rigs operating decreased to 192, as compared to an average of 206 drilling rigs operating during the same period in 2012. +We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource +plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of December 31, 2013, we have completed 124 new APEX ® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 20 additional new APEX ® rigs in 2014. In connection with horizontal shale and other unconventional resource plays, we have added equipment +to perform service intensive fracturing jobs. As of December 31, 2013, we had approximately 763,000 hydraulic horsepower in our pressure pumping fleet. This is a net increase of approximately 610,000 horsepower since the end of 2009. Low +natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America. +We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term +of six months or more. Our backlog as of December 31, 2013 was approximately $946 million. We expect approximately $660 million of our backlog to be realized in 2014. We generally calculate our backlog by multiplying the day rate under our term +drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions +in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are +subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts for which we have received an early termination notice, our backlog +calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate. See Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Not Ultimately Be Realized as +Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment. +For the three years ended +December 31, 2013, our operating revenues from continuing operations consisted of the following (dollars in thousands): +2013 +2012 +2011 +Contract drilling +$ +1,679,611 +62 +% +$ +1,821,713 +67 +% +$ +1,669,581 +65 +% +Pressure pumping +979,166 +36 +841,771 +31 +845,803 +33 +Oil and natural gas +57,257 +2 +59,930 +2 +50,559 +2 +$ +2,716,034 +100 +% +$ +2,723,414 +100 +% +$ +2,565,943 +100 +% +Generally, the profitability of our business is impacted most by two primary factors in our contract +drilling segment: our average number of rigs operating and our average revenue per operating day. During 2013, our average number of rigs operating was 184 in the United States and 8 in Canada compared to 214 in the United States and 7 in +Canada in 2012 and 205 in the United States and 11 in Canada in 2011. Our average +25 +Table of Contents +revenue per operating day was $24,020 in 2013 compared to $22,540 in 2012 and $21,200 in 2011. We had consolidated net income of $188 million for 2013 compared to $299 million for 2012. The +decrease in consolidated net income was primarily due to lower revenue as a result of fewer rigs operating, lower profitability on pressure pumping revenues, higher depreciation expense and a gain on assets disposals in 2012 with no similar gain in +2013. Depreciation, depletion, amortization and impairment expense for 2013 includes a charge of $7.9 million related to removing 48 rigs from our marketable fleet. It also includes a charge of $29.9 million related to 55 mechanical rigs that +were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs. +Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural +gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing +for our services. Natural gas prices and our monthly average number of rigs operating have declined from recent highs. In December 2013, our average number of rigs operating was 187 in the United States and 9 in Canada. +We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues and various other +factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report. +Critical Accounting Policies +In addition to established accounting +policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue +recognition, the use of estimates and oil and natural gas properties. +Property and equipment — Property and +equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line +method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances (“triggering events”) indicate that the carrying values of certain +assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of +our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s +expectations of future trends, we estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as +management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book +value. Any provision for impairment is measured at fair value. +On a periodic basis, we evaluate our fleet of drilling rigs for +marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling +longer horizontal wells using high capacity rigs). In connection with our ongoing planning process, we evaluated our then-current fleet of marketable drilling rigs in 2013, 2012 and 2011 and identified 48, 36 and 53 rigs, during each of those years, +respectively, that we determined would no longer be marketed as rigs based on our assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as well as our assessment of future demand and the +suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs +26 +Table of Contents +were transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs were retired. The net book values of these assets of $7.9 million in 2013, +$5.2 million in 2012 and $15.7 million in 2011 were expensed in our consolidated statements of operations. +In 2013, due +to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded in our consolidated statement of operations a charge of $29.9 million related to 55 mechanical rigs that were not under +contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. +We also evaluate our fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure +pumping equipment that would be retired. The net book value of these assets of $7.3 million was expensed in our consolidated statements of operations. There were no similar charges in 2013 or 2011. +In light of the levels of activity and revenue per operating day experienced by us and our peers in 2013, 2012 and 2011, we concluded that +no triggering events occurred during these years with respect to our contract drilling segment as a whole which would indicate that the carrying amounts of long-lived assets in that segment may not be recoverable. We also concluded that no +triggering event occurred with respect to our pressure pumping segment in 2013, 2012 or 2011. Impairment considerations related to our oil and natural gas segment are discussed below. +Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. We evaluate goodwill at +least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our +reporting units for impairment testing have been determined to be the same as our operating segments. We currently have goodwill in our contract drilling and pressure pumping operating segments. We first determine whether it is more likely than not +that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, we may perform the +first step of quantitative testing for goodwill impairment in lieu of performing a qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If +the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any +remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall. +In connection with our annual goodwill impairment assessment as of December 31, 2012, we determined based on an assessment of +qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, we considered the continued demand +experienced during 2012 for our services in the contract drilling and pressure pumping businesses. We also considered the then current and expected levels of commodity prices for crude oil and natural gas, which influence the overall level of +business activity in these operating segments. Additionally, operating results for 2012 and forecasted operating results for 2013 were also taken into account. Our overall market capitalization and the large amount of calculated excess of the fair +values of our reporting units over their carrying values and lack of significant changes in the key assumptions from our 2010 quantitative Step 1 assessment of goodwill were also considered. +We performed a quantitative impairment assessment of our goodwill as of December 31, 2013. In completing the first step of the +analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting units. In developing this fair value estimate, we applied key +assumptions including an assumed discount rate of 11.87% for the contract drilling reporting unit and an assumed discount rate of 12.40% for the pressure pumping reporting unit. An assumed long-term growth rate of 3.00% was used for both reporting +units. Based on the +27 +Table of Contents +results of the first step of the impairment test in 2013, we concluded that no impairment was indicated in our contract drilling or pressure pumping reporting units as the estimated fair value of +each reporting unit exceeded its carrying value. +We have undertaken extensive efforts in the past several years to upgrade our +fleet of equipment and believe that we are well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional +vertical wells that has resulted primarily from low natural gas prices. In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, +and such impairment could be material. +Revenue recognition — Revenues from daywork drilling and pressure pumping +activities are recognized as services are performed. Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells we drilled in 2013, 2012 and 2011 were drilled under +daywork contracts. +Use of estimates — The preparation of financial statements in conformity with accounting +principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and +liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation, depletion and amortization, +• +fair values of assets acquired and liabilities assumed in acquisitions, +• +goodwill and long-lived asset impairments, and +• +reserves for self-insured levels of insurance coverage. +Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of +accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are +charged to expense when such determination is made. 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 whether sufficient progress +is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider +the well costs 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 and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total +proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil +and natural gas reserves for each respective field. +We review our proved oil and natural gas properties for impairment +whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our +expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is +measured and recognized as the difference between net book value and fair value. The fair +28 +Table of Contents +value estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field and the net future cash inflows from developing and +operating these fields. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and +abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $4.0 million, $1.9 +million and $3.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion, amortization and impairment in the consolidated statements of operations. +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. +Liquidity and Capital Resources +As of December 31, 2013, we had working capital of $454 million, including cash and cash equivalents of $250 million, compared to working capital of $340 million and cash and cash equivalents of $111 +million at December 31, 2012. +During 2013, our sources of cash flow included: +• +$889 million from operating activities, +• +$11.8 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and +• +$10.4 million in proceeds from the disposal of property and equipment. +During 2013, we used $73.5 million to repurchase shares of our common stock, $29.1 million to pay dividends on our common stock, $6.3 +million to repay long-term debt and $662 million: +• +to build new drilling rigs and pressure pumping equipment, +• +to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment, +• +to acquire and procure equipment and facilities for our drilling and pressure pumping operations, and +• +to fund investments in oil and natural gas properties on a working interest basis. +We paid cash dividends during the year ended December 31, 2013 as follows: +Per Share +Total +(in thousands) +Paid on March 29, 2013 +$ +0.05 +$ +7,312 +Paid on June 28, 2013 +0.05 +7,361 +Paid on September 30, 2013 +0.05 +7,231 +Paid on December 31, 2013 +0.05 +7,208 +Total cash dividends +$ +0.20 +$ +29,112 +On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of +$0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of our credit facilities and other factors. +On August 1, +2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. On July 25, 2012, our Board of Directors terminated the remaining +authority under the 2007 stock buyback program, and approved a +29 +Table of Contents +new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions. On September 6, 2013, the Company’s Board +of Directors terminated any remaining authority under the 2012 stock buyback program, and approved a new stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated +transactions. As of December 31, 2013, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as +treasury stock. +We acquired shares of stock from employees during 2013, 2012 and 2011 that are accounted for as treasury +stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options by employees. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of +stock options, the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (the “2005 Plan”) and not pursuant to the stock buyback program. +Treasury stock acquisitions during +the year ended December 31, 2013, 2012 and 2011 were as follows (dollars in thousands): +2013 +2012 +2011 +Shares +Cost +Shares +Cost +Shares +Cost +Treasury shares at beginning of period +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +27,343,814 +$ +620,445 +Purchases pursuant to stock buyback programs: +2007 program +— +— +4,708,784 +70,092 +8,689 +255 +2012 program +2,567,266 +51,107 +5,863,451 +98,892 +— +— +2013 program +602,564 +12,517 +— +— +— +— +Acquisitions Pursuant to the 2005 Long-Term Incentive Plan +951,489 +22,213 +86,932 +1,308 +135,068 +4,059 +Treasury shares at end of period +42,268,057 +$ +880,888 +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +On September 27, 2012, we entered into a credit agreement (the “Credit Agreement”). The +Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced a previous senior unsecured revolving credit facility. +The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility +contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time. +The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments which commenced +December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% +of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments. +Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, +not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility. +Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The +applicable margin on LIBOR +30 +Table of Contents +rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of +December 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the amount +available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%. +The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization +ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must +not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and +amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2013. The Credit Agreement also contains customary representations, +warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. +Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial +and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have +the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to +insolvency and bankruptcy such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit. +As of December 31, 2013, we had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. We +had $39.8 million in letters of credit outstanding at December 31, 2013 and, as a result, had available borrowing capacity of approximately $460 million at that date. +On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a +private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020. +On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior +Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We will pay interest on the Series B Notes on April 5 and October 5 of each year. The +Series B Notes will mature on June 14, 2022. +The Series A Notes and Series B Notes are prepayable at our option, in whole +or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we +must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the +principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date. +The respective note purchase +agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total +borrowed money indebtedness to (b) the sum of such +31 +Table of Contents +indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio +as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior quarters to interest charges for the same period. We were in +compliance with these covenants at December 31, 2013. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. +Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the +financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other +insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately +due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable. +We believe that our liquidity as of December 31, 2013, which includes approximately $454 million in working capital and +approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make +improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from +operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all. +Commitments and Contingencies — As of December 31, 2013, we maintained letters of credit in the aggregate amount of $39.8 +million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various +times during the year and are typically renewed. As of December 31, 2013, no amounts had been drawn under the letters of credit. +As of December 31, 2013, we had commitments to purchase approximately $225 million of major equipment for our drilling and pressure pumping businesses. +Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. +These agreements expire in 2016 and 2017. As of December 31, 2013, the remaining obligation under these agreements was approximately $25.2 million, of which materials with a total purchase price of approximately $7.7 million are expected to be +delivered during 2014. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. +In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such +vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to +purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2013, advances of approximately $11.8 million had been made under this agreement and repayments of approximately +$2.6 million had been received resulting in a balance outstanding of approximately $9.2 million. +In May 2013, the U.S. Equal +Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and +race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC are engaged in the statutory conciliation process. If such +conciliation process is unsuccessful, we believe that litigation will ensue. We intend to defend ourself vigorously and, based on the information available +32 +Table of Contents +to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no +assurance as to the ultimate outcome of this matter. +Trading and Investing — We have not engaged in trading +activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts. +Contractual Obligations +The following table presents information with respect to our contractual obligations as of December 31, 2013 (dollars in thousands): +Payments due by period +Total +Less than +1 year +1-3 years +3-5 years +More than 5 +years +Term loan(1) +$ +92,500 +$ +10,000 +$ +41,250 +$ +41,250 +— +Interest on term loan(2) +6,329 +2,247 +3,572 +510 +— +Series A Notes(3) +300,000 +— +— +— +300,000 +Interest on Series A Notes(4) +100,850 +14,910 +29,820 +29,820 +26,300 +Series B Notes(5) +300,000 +— +— +— +300,000 +Interest on Series B Notes(6) +108,316 +12,810 +25,620 +25,620 +44,266 +Equipment purchases(7) +225,354 +225,354 +— +— +— +Inventory purchases(8) +25,198 +7,735 +15,438 +2,025 +— +$ +1,158,547 +$ +273,056 +$ +115,700 +$ +99,225 +$ +670,566 +(1) +Represents repayments of borrowings under the term loan portion of the Credit Agreement. The term loan matures on September 27, 2017. +(2) +Interest to be paid on term loan using 2.50% rate in effect as of December 31, 2013. +(3) +Principal repayment of the Series A Notes is required at maturity on October 5, 2020. +(4) +Interest to be paid on the Series A Notes using 4.97% coupon rate. +(5) +Principal repayment of the Series B Notes is required at maturity on June 14, 2022 +(6) +Interest to be paid on the Series B Notes using 4.27% coupon rate. +(7) +Represents commitments to purchase major equipment to be delivered in 2014 based on expected delivery dates. +(8) +Represents commitments to purchase proppants and chemicals for our pressure pumping business. +33 +Table of Contents +Off-Balance Sheet Arrangements +We had no off-balance sheet arrangements at December 31, 2013. +Results of Operations +Comparison of the years ended +December 31, 2013 and 2012 +The following tables summarize operations by business segment for the years ended +December 31, 2013 and 2012: +Year Ended December 31, +Contract Drilling +2013 +2012 +% Change +(Dollars in thousands) +Revenues +$ +1,679,611 +$ +1,821,713 +(7.8 +)% +Direct operating costs +968,754 +1,075,491 +(9.9 +)% +Margin(1) +710,857 +746,222 +(4.7 +)% +Selling, general and administrative +5,867 +6,513 +(9.9 +)% +Depreciation, amortization and impairment +438,728 +390,316 +12.4 +% +Operating income +$ +266,262 +$ +349,393 +(23.8 +)% +Operating days +69,918 +80,833 +(13.5 +)% +Average revenue per operating day +$ +24.02 +$ +22.54 +6.6 +% +Average direct operating costs per operating day +$ +13.86 +$ +13.31 +4.1 +% +Average margin per operating day(1) +$ +10.17 +$ +9.23 +10.2 +% +Average rigs operating +192 +221 +(13.1 +)% +Capital expenditures +$ +504,508 +$ +744,949 +(32.3 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per operating day is defined as margin divided by operating days. +The demand for our contract +drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has contributed to an excess capacity of land drilling rigs compared to +demand. Recently, customer demand has shifted away from mechanically powered drilling rigs to electric powered drilling rigs, reducing the utilization rates of our mechanically powered drilling rigs. The average market price of natural gas and oil +for each of the fiscal quarters and full year in 2013 and 2012 follows: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2012: +Average natural gas price per +Mcf(1) +$ +2.45 +$ +2.28 +$ +2.88 +$ +3.40 +$ +2.75 +Average oil price per Bbl(2) +$ +102.88 +$ +93.42 +$ +92.24 +$ +87.96 +$ +94.12 +2013: +Average natural gas price per +Mcf(1) +$ +3.49 +$ +4.01 +$ +3.55 +$ +3.85 +$ +3.73 +Average oil price per Bbl(2) +$ +94.34 +$ +94.10 +$ +105.84 +$ +97.34 +$ +97.91 +(1) +The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +34 +Table of Contents +Revenues and direct operating costs decreased in 2013 compared to 2012 +as a result of a decrease in the number of rigs operating. A greater proportion of our high specification APEX ® +rigs working combined with early contract termination revenues caused an increase in the average revenue per operating day. Capital expenditures were incurred in 2013 and 2012 to build new drilling rigs, to modify and upgrade existing drilling rigs +and to acquire additional equipment including top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately +$7.9 million in 2013 and approximately $5.2 million in 2012 of charges related to drilling equipment on drilling rigs that were retired from our marketable fleet. We retired 48 rigs from our marketable fleet in 2013 and retired 36 rigs from our +marketable fleet in 2012. In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded additional depreciation, amortization and impairment expense of $29.9 million +related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no +similar charges in 2012 or 2011. Significant capital expenditures incurred in recent years to add new rig capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Pressure Pumping +2013 +2012 +% Change +(Dollars in thousands) +Revenues +$ +979,166 +$ +841,771 +16.3 +% +Direct operating costs +744,243 +580,878 +28.1 +% +Margin(1) +234,923 +260,893 +(10.0 +)% +Selling, general and administrative +17,695 +17,036 +3.9 +% +Depreciation, amortization and impairment +129,984 +111,062 +17.0 +% +Operating income +$ +87,244 +$ +132,795 +(34.3 +)% +Fracturing jobs +1,261 +1,229 +2.6 +% +Other jobs +4,800 +5,659 +(15.2 +)% +Total jobs +6,061 +6,888 +(12.0 +)% +Average revenue per fracturing job +$ +705.57 +$ +590.70 +19.4 +% +Average revenue per other job +$ +18.63 +$ +20.46 +(8.9 +)% +Average revenue per total job +$ +161.55 +$ +122.21 +32.2 +% +Average direct operating costs per total job +$ +122.79 +$ +84.33 +45.6 +% +Average margin per total job(1) +$ +38.76 +$ +37.88 +2.3 +% +Margin as a percentage of total revenues(1) +24.0 +% +31.0 +% +(22.6 +)% +Capital expenditures +$ +122,782 +$ +194,117 +(36.7 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. +In connection with the development of unconventional reservoirs, customers have continued to increase the average size of the fracturing jobs. As a result, we have experienced an increase in the size of +these multi-stage fracturing jobs resulting in higher revenues and costs. Average revenue per fracturing job increased as a result of this increase in the larger multi-stage fracturing jobs in 2013 as compared to 2012. Average direct operating costs +per total job increased primarily as a result of increased amounts of materials and labor used on the larger multi-stage fracturing jobs. Depreciation, amortization and impairment expense increased in 2013 due primarily to significant capital +expenditures incurred in recent years to add capacity. In 2012, depreciation, amortization and +35 +Table of Contents +impairment expenses included approximately $7.3 million related to the retirement of certain pressure pumping equipment. There were no comparable charges in 2013. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2013 +2012 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +51,583 +$ +55,335 +(6.8 +)% +Revenues — Natural gas and liquids +5,674 +4,595 +23.5 +% +Revenues — Total +57,257 +59,930 +(4.5 +)% +Direct operating costs +12,909 +11,303 +14.2 +% +Margin(1) +44,348 +48,627 +(8.8 +)% +Depletion and impairment +24,400 +21,417 +13.9 +% +Operating income +$ +19,948 +$ +27,210 +(26.7 +)% +Capital expenditures +$ +31,245 +$ +29,888 +4.5 +% +(1) +Margin is defined as revenues less direct operating costs and excludes depletion and impairment. +Oil revenues decreased as a result of lower production partially offset by higher average oil prices. Natural gas and liquids revenue +increased due to higher average prices and higher production. Direct operating costs and depletion expense also increased primarily due to the addition of new wells. Depletion and impairment expense in 2013 includes approximately $4.0 million of oil +and natural gas property impairments compared to approximately $1.9 million of oil and natural gas property impairments in 2012. +Year Ended December 31, +Corporate and Other +2013 +2012 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +50,290 +$ +40,924 +22.9 +% +Depreciation +$ +4,357 +$ +3,819 +14.1 +% +Net gain on asset disposals +$ +(3,384 +) +$ +(33,806 +) +(90.0 +)% +Provision for bad debts +$ +— +$ +1,100 +(100.0 +)% +Interest income +$ +918 +$ +554 +65.7 +% +Interest expense +$ +28,359 +$ +22,750 +24.7 +% +Other income +$ +1,691 +$ +508 +232.9 +% +Capital expenditures +$ +3,926 +$ +5,034 +(22.0 +)% +Selling, general and administrative expense for 2013 increased primarily due to higher costs associated +with stock-based compensation and expenses to evaluate and prepare for international growth opportunities. Selling, general and administrative expense in 2012 included a reduction in personnel costs related to the final determination of payouts +under the 2009 Performance Unit Awards upon the completion of the performance period. There was no similar reduction in 2013. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate +to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction +sale of certain excess drilling assets. An additional provision for bad debts was recorded in 2012 with no similar increase in 2013. Interest expense increased in 2013 primarily due to a full year of interest charges related to the $300 million +of Series B Senior Notes issued and sold on June 14, 2012. +36 +Table of Contents +Comparison of the years ended December 31, 2012 and 2011 +The following tables summarize operations by business segment for the years ended December 31, 2012 and 2011: +Year Ended December 31, +Contract Drilling +2012 +2011 +% Change +(Dollars in thousands) +Revenues +$ +1,821,713 +$ +1,669,581 +9.1 +% +Direct operating costs +1,075,491 +972,778 +10.6 +% +Margin(1) +746,222 +696,803 +7.1 +% +Selling, general and administrative +6,513 +6,408 +1.6 +% +Depreciation, amortization and impairment +390,316 +344,312 +13.4 +% +Operating income +$ +349,393 +$ +346,083 +1.0 +% +Operating days +80,833 +78,758 +2.6 +% +Average revenue per operating day +$ +22.54 +$ +21.20 +6.3 +% +Average direct operating costs per operating day +$ +13.31 +$ +12.35 +7.8 +% +Average margin per operating day(1) +$ +9.23 +$ +8.85 +4.3 +% +Average rigs operating +221 +216 +2.3 +% +Capital expenditures +$ +744,949 +$ +784,686 +(5.1 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per operating day is defined as margin divided by operating days. +The demand for our contract +drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States contributed to an excess capacity of land drilling rigs compared to demand. The average market +price of natural gas and oil for each of the fiscal quarters and full year in 2012 and 2011 follows: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2011: +Average natural gas price per +Mcf(1) +$ +4.18 +$ +4.37 +$ +4.12 +$ +3.32 +$ +4.00 +Average oil price per Bbl(2) +$ +93.50 +$ +102.22 +$ +89.72 +$ +93.99 +$ +94.86 +2012: +Average natural gas price per +Mcf(1) +$ +2.45 +$ +2.28 +$ +2.88 +$ +3.40 +$ +2.75 +Average oil price per Bbl(2) +$ +102.88 +$ +93.42 +$ +92.24 +$ +87.96 +$ +94.12 +(1) +The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of +operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual day rates. Average direct operating costs per operating day +increased in 2012 due primarily to higher labor-related and rig mobilization costs. The increase in operating days was largely due to increased demand during the first six months of 2012 resulting from higher oil prices and the addition of newbuild +APEX ® rigs into our drilling fleet. Capital +37 +Table of Contents +expenditures were incurred in 2012 and 2011 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional equipment including top drives, drill pipe, drill +collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately $5.2 million in 2012 and approximately $15.7 million in 2011 of charges +related to drilling equipment and drilling rigs that were retired from our marketable fleet. We retired 36 rigs from our marketable fleet in 2012 and retired 53 rigs from our marketable fleet in 2011. Significant capital expenditures incurred in +recent years to add new rig capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Pressure Pumping +2012 +2011 +% Change +(Dollars in thousands) +Revenues +$ +841,771 +$ +845,803 +(0.5 +)% +Direct operating costs +580,878 +561,398 +3.5 +% +Margin(1) +260,893 +284,405 +(8.3 +)% +Selling, general and administrative +17,036 +17,686 +(3.7 +)% +Depreciation, amortization and impairment +111,062 +73,279 +51.6 +% +Operating income +$ +132,795 +$ +193,440 +(31.4 +)% +Fracturing jobs +1,229 +1,531 +(19.7 +)% +Other jobs +5,659 +7,010 +(19.3 +)% +Total jobs +6,888 +8,541 +(19.4 +)% +Average revenue per fracturing job +$ +590.70 +$ +467.85 +26.3 +% +Average revenue per other job +$ +20.46 +$ +18.48 +10.7 +% +Average revenue per total job +$ +122.21 +$ +99.03 +23.4 +% +Average direct operating costs per total job +$ +84.33 +$ +65.73 +28.3 +% +Average margin per total job(1) +$ +37.88 +$ +33.30 +13.8 +% +Margin as a percentage of revenues(1) +31.0 +% +33.6 +% +(7.7 +)% +Capital expenditures +$ +194,117 +$ +198,061 +(2.0 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. +Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional +equipment to meet this demand and expand our area of operations. As a result, although the total number of fracturing jobs has decreased, we have experienced an increase in these larger multi-stage fracturing jobs as a proportion of the total +fracturing jobs we performed. Average revenue per fracturing job increased primarily as a result of this increase in the number of larger multi-stage fracturing jobs in 2012 as compared to 2011. Average revenue per other job increased as a result of +a change in job mix. The increase in the number of larger multi-stage fracturing jobs caused an increase in average direct operating costs per total job primarily increased costs of materials and higher labor-related costs. Depreciation, +amortization and impairment expense increased in 2012 due to a charge of approximately $7.3 million related to approximately 37,000 horsepower of pressure pumping equipment that was +38 +Table of Contents +retired. Significant capital expenditures incurred in recent years to add capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2012 +2011 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +55,335 +$ +44,495 +24.4 +% +Revenues — Natural gas and liquids +4,595 +6,064 +(24.2 +)% +Revenues — Total +59,930 +50,559 +18.5 +% +Direct operating costs +11,303 +9,615 +17.6 +% +Margin(1) +48,627 +40,944 +18.8 +% +Depletion and impairment +21,417 +16,962 +26.3 +% +Operating income +$ +27,210 +$ +23,982 +13.5 +% +Capital expenditures +$ +29,888 +$ +22,884 +30.6 +% +(1) +Margin is defined as revenues less direct operating costs and excludes depletion and impairment. +Oil revenues increased primarily as a result of increased production. Oil production increased primarily due to the addition of new wells. +Natural gas and liquids revenue decreased as a result of lower prices partially offset by increased production. Depletion and impairment expense in 2012 includes approximately $1.9 million of oil and natural gas property impairments compared to +approximately $3.0 million of oil and natural gas property impairments in 2011. Depletion expense increased approximately $5.6 million in 2012 compared to 2011 primarily due to increased production. +Year Ended December 31, +Corporate and Other +2012 +2011 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +40,924 +$ +40,177 +1.9 +% +Depreciation +$ +3,819 +$ +2,726 +40.1 +% +Net gain on asset disposals +$ +(33,806 +) +$ +(4,999 +) +576.3 +% +Provision for bad debts +$ +1,100 +$ +— +N/M +Interest income +$ +554 +$ +187 +196.3 +% +Interest expense +$ +22,750 +$ +15,652 +45.3 +% +Other income +$ +508 +$ +582 +(12.7 +)% +Capital expenditures +$ +5,034 +$ +5,947 +15.4 +% +The increase in depreciation expense relates primarily to a new enterprise resource planning system. Gains +and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of +approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction sale of certain excess drilling assets. A provision for bad debts was recognized in 2012 with respect to accounts +receivable balances that are estimated to be uncollectible. Interest expense increased in 2012 due primarily to deferred debt issuance costs of $978,000 that were charged to expense as a result of the early termination of the prior credit facility +and to interest charges related to the $300 million of +39 +Table of Contents +Series B Senior Notes issued and sold on June 14, 2012. Capital expenditures decreased in 2012 due to less activity with respect to the implementation of the new enterprise resource planning +system. +Year Ended December 31, +Discontinued Operations: +2012 +2011 +% Change +(Dollars in thousands) +Electric wireline revenue +$ +— +$ +1,104 +(100 +)% +Electric wireline direct operating costs +$ +— +$ +1,831 +(100 +)% +Selling, general and administrative +$ +— +$ +46 +(100 +)% +Income tax benefit +$ +— +$ +(209 +) +(100 +)% +Loss from discontinued operations, net of income taxes +$ +— +$ +(367 +) +(100 +)% +On January 27, 2011, we sold our electric wireline business, which had been acquired by us on +October 1, 2010. The results of operations of this business have been classified as a discontinued operation. +Income Taxes +Year Ended December 31, +2013 +2012 +2011 +(Dollars in thousands) +Income from continuing operations before income tax +$ +296,441 +$ +475,673 +$ +510,718 +Income tax expense +$ +108,432 +$ +176,196 +$ +187,938 +Effective tax rate +36.6 +% +37.0 +% +36.8 +% +The effective tax rate is a result of a federal rate of 35.0% adjusted as follows: +2013 +2012 +2011 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +3.7 +2.5 +2.5 +Permanent differences +(1.5 +) +(0.2 +) +(0.1 +) +Other, net +(0.6 +) +(0.3 +) +(0.6 +) +Effective tax rate +36.6 +% +37.0 +% +36.8 +% +The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 +(as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent difference for 2011 does not include any +deduction as it is limited to taxable income and we had a tax loss in 2011. The permanent difference for 2012 does not include any deduction as it is limited to taxable income and we did not have taxable income in 2012 due to the utilization of net +operating loss carryforwards. The permanent difference for 2013 includes a deduction of $10.0 million as we fully utilized our remaining net operating loss carryforwards. +We record deferred federal income taxes based primarily on the temporary differences between the book and tax bases of our assets and liabilities. Deferred tax assets and liabilities are measured using +enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We recognized deferred tax expense of approximately $51 million in 2013, $160 million in 2012 and $159 million in 2011. +On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are +lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the +Canadian assets. +40 +Table of Contents +As a result of the above conversion, our Canadian assets are no longer directly subject to +United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and intend to do so for the +foreseeable future. As a result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $38.5 million as of December 31, 2013. The unrecognized deferred tax +liability associated with these earnings was approximately $5.9 million, net of available foreign tax credits. This liability would be recognized if we received a dividend of the unremitted earnings. +Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition +Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about +future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as market supply and demand, domestic and international military, political, economic and weather conditions, the +ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and production and the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market +prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the +prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets +continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot +price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of +drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil +prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United +States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined from historic highs. +We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our +drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or +curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services. +Impact of Inflation +Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2013. We believe +that inflation will not have a significant near-term impact on our financial position. +Recently Issued Accounting Standards +In February 2013, the FASB issued an accounting standards update that requires additional disclosures regarding +reclassifications out of accumulated other comprehensive income. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012, and became effective for us in the quarter ended +March 31, 2013. The adoption of this update did not have a material impact on the disclosures included in our consolidated financial statements. We include in accumulated other comprehensive income the cumulative translation adjustment of our +foreign subsidiary. +41 +Table of Contents +In February 2013, the FASB issued an accounting standards update to provide guidance for the +recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations +addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount +the reporting entity expects to pay on behalf of its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are +effective during interim and annual periods beginning after December 15, 2013. The adoption of this update is not expected to have a material impact on our consolidated financial statements. +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk associated with any borrowings that we have under our term credit facility or our +revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans +ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2013, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2013, we had no borrowings outstanding under +our revolving credit facility and $92.5 million outstanding under our term credit facility at an interest rate of 2.50%. The interest rate on the borrowing outstanding under our term credit facility is variable and adjusts at each interest payment +date based on our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowings outstanding under our term credit facility as of December 31, 2013 would increase our annual cash interest expense by +approximately $900,000. +We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling +operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations +will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition. +The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term +maturity of these items. +Item 8. +Financial Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference. +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 9A. +Controls and Procedures. +Disclosure Controls and Procedures: +Under the supervision and with the +participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is +defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2013, our disclosure controls and +procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and +is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. +42 +Table of Contents +Management’s Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange +Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013, +based on the Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial +reporting was effective as of December 31, 2013. +The effectiveness of our internal control over financial reporting as of +December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of +this Report. +Changes in Internal Control over Financial Reporting: +There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have +materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +Item 9B. +Other Information. +None. +43 +Table of Contents +PART III +Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities +Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference. +Item 10. +Directors, Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive +officer and principal financial and accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com . We intend to disclose any amendments to or waivers from this code +on our website. +Item 11. +Executive Compensation. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 14. +Principal Accounting Fees and Services. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +44 +Table of Contents +PART IV +Item 15. +Exhibits and Financial Statement Schedule. +(a)(1) Financial Statements +See Index to Consolidated Financial +Statements on page F-1 of this Report. +(a)(2) Financial Statement Schedule +Schedule II — Valuation and qualifying accounts is filed herewith on page S-1. +All other financial statement schedules have been omitted because they are not applicable or the information required therein is included +elsewhere in the financial statements or notes thereto. +(a)(3) Exhibits +The following exhibits are filed herewith or incorporated by reference herein. +2.1 +Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure +Pumping Services, LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +2.2 +Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +2.3 +Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +3.1 +Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, +2004 and incorporated herein by reference). +3.2 +Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period +ended June 30, 2004 and incorporated herein by reference). +3.3 +Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +3.4 +Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +10.1 +Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). +10.2 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the +quarterly period ended June 30, 2003 and incorporated herein by reference).* +45 +Table of Contents +10.3 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on +Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).* +10.4 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by +reference).* +10.5 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated +herein by reference). +10.6 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +10.7 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.8 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.9 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q and +incorporated herein by reference).* +10.10 +Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time (filed February 19, 2010 +as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference).* +10.11 +Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).* +10.12 +Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).* +10.13 +Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John +E. Vollmer III (filed 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).* +10.14 +Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form +10-K, as amended, and incorporated herein by reference).* +10.15 +Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Management Services, LLC and Douglas J. Wall (filed September 24, 2012 as Exhibit 10.1 to the +Company’s Current Report on Form 8-K, and incorporated herein by reference).* +46 +Table of Contents +10.16 +Employment Agreement, effective as of January 1, 2012, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb (filed February 10, 2012 as Exhibit 10.17 to the +Company’s Annual Report on Form 10-K for the year ended December 31, 2011 and incorporated herein by reference). * +10.17 +Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry +H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler, William Andrew Hendricks, Jr. and Michael W. Conlon (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year +ended December 31, 2003 and incorporated herein by reference).* +10.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as +Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.19 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on +February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, +2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.21 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.22 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.23 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to +the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.24 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.25 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as +Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* +10.26 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed July 30, +2012 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* +47 +Table of Contents +10.27 +Form of Offer Letter to William Andrew Hendricks, Jr. dated March 14, 2012 (filed March 16, 2012 as Exhibit 99.3 to the Company’s Current Report on Form 8-K and incorporated +herein by reference).* +10.28 +Severance Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William A. Hendricks, Jr. (filed July 30, 2012 as Exhibit 10.2 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* +10.29 +Credit Agreement dated September 27, 2012, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender +and lender and each of the other letter of credit issuer and lender parties thereto (filed September 28, 2012 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +10.30 +Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +10.31 +Note Purchase Agreement dated June 14, 2012 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed June 18, 2012 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.+ +23.1 +Consent of Independent Registered Public Accounting Firm.+ +31.1 +Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +31.2 +Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +32.1 +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of +2002.+ +101 +The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting +Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Stockholders’ Equity, (v) the Consolidated +Statements of Cash Flows, and (vi) Notes to Consolidated Financial Statements.+ +* +Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. ++ +Filed herewith. +48 +Table of Contents +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements: +Consolidated Balance Sheets as of December 31, 2013 and 2012 +F-3 +Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and +2011 +F-4 +Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and +2011 +F-5 +Consolidated Statements of Changes In Stockholders’ Equity for the years ended December +31, 2013, 2012 and 2011 +F-6 +Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and +2011 +F-7 +Notes to Consolidated Financial Statements +F-8 +Schedule II — Valuation and Qualifying Accounts +S-1 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders +of Patterson-UTI Energy, Inc.: +In our opinion, the consolidated financial +statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2013 and 2012, and the results of their +operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial 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 financial statements. Also in our opinion, the +Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee +of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial +reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express +opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public +Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal +control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over +financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as +we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company’s +internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted +accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions +and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that +receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized +acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its +inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of +changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Houston, Texas +February 14, 2014 +F-2 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +December 31, +2013 +2012 +(In thousands, +except share data) +ASSETS +Current assets: +Cash and cash equivalents +$ +249,509 +$ +110,723 +Accounts receivable, net of allowance for doubtful accounts of $3,674 and $3,513 at December 31, 2013 and 2012, +respectively +451,517 +465,517 +Inventory +21,248 +26,889 +Deferred tax assets, net +32,952 +52,959 +Other +53,424 +43,903 +Total current assets +808,650 +699,991 +Property and equipment, net +3,635,541 +3,615,383 +Goodwill and intangible assets +167,470 +171,463 +Deposits on equipment purchases +52,560 +43,776 +Other +22,906 +26,298 +Total assets +$ +4,687,127 +$ +4,556,911 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable +$ +173,150 +$ +188,823 +Federal and state income taxes payable +10,670 +6,158 +Accrued expenses +160,457 +158,632 +Current portion of long-term debt +10,000 +6,250 +Total current liabilities +354,277 +359,863 +Long-term debt +682,500 +692,500 +Deferred tax liabilities, net +887,864 +857,302 +Other +6,489 +6,589 +Total liabilities +1,931,130 +1,916,254 +Commitments and contingencies (see Note 8) +Stockholders’ equity: +Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued +— +— +Common stock, par value $.01; authorized 300,000,000 shares with 186,487,246 and 184,059,900 issued and 144,219,189 and +145,913,162 outstanding at December 31, 2013 and 2012, respectively +1,865 +1,841 +Additional paid-in capital +913,505 +863,558 +Retained earnings +2,707,439 +2,548,542 +Accumulated other comprehensive income +14,076 +21,767 +Treasury stock, at cost, 42,268,057 shares and 38,146,738 shares at December 31, 2013 and 2012, respectively +(880,888 +) +(795,051 +) +Total stockholders’ equity +2,755,997 +2,640,657 +Total liabilities and stockholders’ equity +$ +4,687,127 +$ +4,556,911 +The accompanying notes are an integral part of these consolidated financial statements. +F-3 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +Year Ended December 31, +2013 +2012 +2011 +(In thousands, except per share data) +Operating revenues: +Contract drilling +$ +1,679,611 +$ +1,821,713 +$ +1,669,581 +Pressure pumping +979,166 +841,771 +845,803 +Oil and natural gas +57,257 +59,930 +50,559 +Total operating revenues +2,716,034 +2,723,414 +2,565,943 +Operating costs and expenses: +Contract drilling +968,754 +1,075,491 +972,778 +Pressure pumping +744,243 +580,878 +561,398 +Oil and natural gas +12,909 +11,303 +9,615 +Depreciation, depletion, amortization and impairment +597,469 +526,614 +437,279 +Selling, general and administrative +73,852 +64,473 +64,271 +Net gain on asset disposals +(3,384 +) +(33,806 +) +(4,999 +) +Provision for bad debts +— +1,100 +— +Total operating costs and expenses +2,393,843 +2,226,053 +2,040,342 +Operating income +322,191 +497,361 +525,601 +Other income (expense): +Interest income +918 +554 +187 +Interest expense +(28,359 +) +(22,750 +) +(15,652 +) +Other +1,691 +508 +582 +Total other expense +(25,750 +) +(21,688 +) +(14,883 +) +Income from continuing operations before income taxes +296,441 +475,673 +510,718 +Income tax expense: +Current +57,863 +15,760 +28,971 +Deferred +50,569 +160,436 +158,967 +Total income tax expense +108,432 +176,196 +187,938 +Income from continuing operations +188,009 +299,477 +322,780 +Loss from discontinued operations, net of income taxes +— +— +(367 +) +Net income +$ +188,009 +$ +299,477 +$ +322,413 +Basic income per common share: +Income from continuing operations +$ +1.29 +$ +1.96 +$ +2.08 +Loss from discontinued operations, net of income taxes +$ +0.00 +$ +0.00 +$ +0.00 +Net income +$ +1.29 +$ +1.96 +$ +2.08 +Diluted income per common share: +Income from continuing operations +$ +1.28 +$ +1.96 +$ +2.06 +Loss from discontinued operations, net of income taxes +$ +0.00 +$ +0.00 +$ +0.00 +Net income +$ +1.28 +$ +1.96 +$ +2.06 +Weighted average number of common shares outstanding: +Basic +144,356 +151,144 +153,871 +Diluted +145,303 +151,699 +155,304 +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.20 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +Year Ended December 31, +2013 +2012 +2011 +(In thousands) +Net income +$ +188,009 +$ +299,477 +$ +322,413 +Other comprehensive income, net of taxes of $0 for 2013, $0 for 2012 and $0 for 2011: +Foreign currency translation adjustment +(7,691 +) +2,308 +(2,138 +) +Total comprehensive income +$ +180,318 +$ +301,785 +$ +320,275 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY +Common Stock +Additional +Paid-in +Capital +Retained +Earnings +Accumulated +Other +Comprehensive +Income +Treasury +Stock +Total +Number of +Shares +Amount +(In thousands) +Balance, December 31, 2010 +181,538 +1,815 +796,641 +1,987,999 +21,597 +(620,445 +) +2,187,607 +Net income +— +— +— +322,413 +— +— +322,413 +Foreign currency translation adjustment +— +— +— +— +(2,138 +) +— +(2,138 +) +Issuance of restricted stock +782 +8 +(8 +) +— +— +— +— +Vesting of restricted stock units +10 +— +— +— +— +— +— +Forfeitures of restricted stock +(83 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +1,048 +11 +16,800 +— +— +— +16,811 +Stock-based compensation +— +— +20,904 +— +— +— +20,904 +Tax benefit related to stock-based compensation +— +— +6,393 +— +— +— +6,393 +Payment of cash dividends +— +— +— +(31,045 +) +— +— +(31,045 +) +Purchase of treasury stock +— +— +— +— +— +(4,314 +) +(4,314 +) +Balance, December 31, 2011 +183,295 +1,833 +840,731 +2,279,367 +19,459 +(624,759 +) +2,516,631 +Net income +— +— +— +299,477 +— +— +299,477 +Foreign currency translation adjustment +— +— +— +— +2,308 +— +2,308 +Issuance of restricted stock +792 +8 +(8 +) +— +— +— +— +Vesting of restricted stock units +8 +— +— +— +— +— +— +Forfeitures of restricted stock +(99 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +64 +1 +933 +— +— +— +934 +Stock-based compensation +— +— +23,185 +— +— +— +23,185 +Tax expense related to stock-based compensation +— +— +(1,284 +) +— +— +— +(1,284 +) +Payment of cash dividends +— +— +— +(30,302 +) +— +— +(30,302 +) +Purchase of treasury stock +— +— +— +— +— +(170,292 +) +(170,292 +) +Balance, December 31, 2012 +184,060 +$ +1,841 +$ +863,558 +$ +2,548,542 +$ +21,767 +$ +(795,051 +) +$ +2,640,657 +Net income +— +— +— +188,009 +— +— +188,009 +Foreign currency translation adjustment +— +— +— +— +(7,691 +) +— +(7,691 +) +Issuance of restricted stock +1,312 +13 +(13 +) +— +— +— +— +Vesting of restricted stock units +9 +— +— +— +— +— +— +Forfeitures of restricted stock +(84 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +1,190 +12 +19,274 +— +— +— +19,286 +Stock-based compensation +— +— +25,891 +— +— +— +25,891 +Tax benefit related to stock-based compensation +— +— +4,794 +— +— +— +4,794 +Payment of cash dividends +— +— +— +(29,112 +) +— +— +(29,112 +) +Purchase of treasury stock +— +— +— +— +— +(85,837 +) +(85,837 +) +Balance, December 31, 2013 +186,487 +$ +1,865 +$ +913,505 +$ +2,707,439 +$ +14,076 +$ +(880,888 +) +$ +2,755,997 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +Year Ended December 31, +2013 +2012 +2011 +(In thousands) +Cash flows from operating activities: +Net income +$ +188,009 +$ +299,477 +$ +322,413 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion, amortization and impairment +597,469 +526,614 +437,279 +Provision for bad debts +— +1,100 +— +Dry holes and abandonments +89 +308 +1,213 +Deferred income tax expense +50,569 +160,436 +158,967 +Stock-based compensation expense +25,891 +23,185 +20,904 +Net gain on asset disposals +(3,384 +) +(33,806 +) +(4,999 +) +Tax expense related to stock-based compensation +— +(1,284 +) +— +Changes in operating assets and liabilities: +Accounts receivable +12,007 +52,612 +(183,165 +) +Income taxes receivable/payable +4,447 +3,506 +77,618 +Inventory and other assets +570 +5,276 +(13,491 +) +Accounts payable +11,331 +(25,199 +) +41,995 +Accrued expenses +1,973 +(6,048 +) +18,313 +Other liabilities +(100 +) +(837 +) +(8,111 +) +Net cash used in operating activities of discontinued operations +— +— +(339 +) +Net cash provided by operating activities +888,871 +1,005,340 +868,597 +Cash flows from investing activities: +Purchases of property and equipment +(662,461 +) +(973,988 +) +(1,011,578 +) +Proceeds from disposal of assets +10,386 +66,027 +22,495 +Net cash provided by investing activities of discontinued operations +— +— +25,500 +Net cash used in investing activities +(652,075 +) +(907,961 +) +(963,583 +) +Cash flows from financing activities: +Purchases of treasury stock +(73,510 +) +(170,292 +) +(4,314 +) +Dividends paid +(29,112 +) +(30,302 +) +(31,045 +) +Tax benefit related to stock-based compensation +4,794 +— +6,393 +Proceeds from long-term debt +— +400,000 +— +Repayment of long-term debt +(6,250 +) +(93,750 +) +(6,250 +) +Proceeds from borrowings under revolving credit facility +— +123,400 +153,100 +Repayment of borrowings under revolving credit facility +— +(233,400 +) +(43,100 +) +Debt issuance costs +— +(7,581 +) +— +Proceeds from exercise of stock options +6,959 +934 +16,811 +Net cash provided by (used in) financing activities +(97,119 +) +(10,991 +) +91,595 +Effect of foreign exchange rate changes on cash +(891 +) +389 +(275 +) +Net increase (decrease) in cash and cash equivalents +138,786 +86,777 +(3,666 +) +Cash and cash equivalents at beginning of year +110,723 +23,946 +27,612 +Cash and cash equivalents at end of year +$ +249,509 +$ +110,723 +$ +23,946 +Supplemental disclosure of cash flow information: +Net cash (paid) received during the year for: +Interest, net of capitalized interest of $7,775 in 2013, $8,673 in 2012 and $8,415 in 2011 +$ +(26,228 +) +$ +(16,651 +) +$ +(13,177 +) +Income taxes +(42,600 +) +(7,964 +) +59,251 +Non-cash investing and financing activities: +Net increase (decrease) in payables for purchases of property and equipment +$ +(26,899 +) +$ +(27,838 +) +$ +37,838 +Net (increase) decrease in deposits on equipment purchases +(8,784 +) +55,767 +(48,459 +) +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. +Description of Business and Summary of Significant Accounting Policies +A description of the business and basis of presentation follows: +Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries (collectively referred to herein +as “Patterson-UTI” or the “Company”), provides onshore contract drilling services to major and independent oil and natural gas operators in the continental United States, Alaska and western and northern Canada. The Company +provides pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. The Company also invests in oil and natural gas properties on a non-operating working interest basis. +Basis of presentation — The consolidated financial statements include the accounts of Patterson-UTI and its wholly-owned +subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any other entity which would require consolidation. +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 its functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity. +A summary of the significant accounting policies follows: +Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in +the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the +reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. +Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed. +Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells the Company drilled in 2013, 2012 and 2011 were drilled under daywork contracts. +Accounts receivable — Trade accounts receivable are recorded at the invoiced amount. 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 at least quarterly. Significant individual +accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectability. Account balances, when determined to be uncollectable, are charged against the allowance. +Inventories — Inventories consist primarily of sand and other products to be used in conjunction with the Company’s +pressure pumping activities. The inventories are stated at the lower of cost or market, determined by the first-in, first-out method. +Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The +method of depreciation does not change whenever equipment becomes idle. The estimated useful lives, in years, are shown below: +Useful Lives +Drilling rigs and other equipment +1.25-15 +Buildings +15-20 +Other +3-12 +F-8 +Table of Contents +Long-lived assets, including property and equipment, are evaluated for impairment when +certain triggering events or changes in circumstances indicate that the carrying values may not be recoverable over their estimated remaining useful life. +Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of +accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are +charged to expense when such determination is made. 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 whether sufficient +progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, the +Company considers the well costs to be impaired and recognizes the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The +capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on +engineering estimates of total proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on +engineering estimates of total proved oil and natural gas reserves for each respective field. +The Company reviews its proved +oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted +cash flow estimates are prepared based on management’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds +its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair value estimates used in measuring impairment are based on management’s expectations of future +commodity prices over the life of the respective field and the net future cash inflows from developing and operating these fields. The Company reviews unproved oil and natural gas properties quarterly to assess potential impairment. The +Company’s impairment assessment is made on a lease-by-lease basis and considers factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related +property costs are expensed. +Goodwill — Goodwill is considered to have an indefinite useful economic life and is +not amortized. The Company assesses impairment of its goodwill at least annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value. +Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments +which extend the life or improve existing property and equipment are capitalized. +Disposals — Upon disposition of +property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations. +Net income per common share — The Company provides a dual presentation of its net income per common share in its consolidated statements of operations: Basic net income per common share +(“Basic EPS”) and diluted net income per common share (“Diluted EPS”). +Basic EPS excludes dilution and is +computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of +common shares outstanding during the period, excluding non-vested shares of restricted stock. +Diluted EPS is based on the +weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted +stock units is determined using the treasury stock +F-9 +Table of Contents +method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed +earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock. +The following table presents information necessary to calculate income from continuing operations per share, loss from discontinued operations per share and net income per share for the years ended +December 31, 2013, 2012 and 2011, as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share +amounts): +2013 +2012 +2011 +BASIC EPS: +Income from continuing operations +$ +188,009 +$ +299,477 +$ +322,780 +Adjust for income attributed to holders of non-vested restricted stock +(1,859 +) +(2,532 +) +(2,545 +) +Income from continuing operations attributed to common stockholders +$ +186,150 +$ +296,945 +$ +320,235 +Loss from discontinued operations, net +$ +— +$ +— +$ +(367 +) +Adjust for loss attributed to holders of non-vested restricted stock +— +— +3 +Loss from discontinued operations attributed to common stockholders +$ +— +$ +— +$ +(364 +) +Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock +144,356 +151,144 +153,871 +Basic income from continuing operations per common share +$ +1.29 +$ +1.96 +$ +2.08 +Basic loss from discontinued operations per common share +$ +0.00 +$ +0.00 +$ +0.00 +Basic net income per common share +$ +1.29 +$ +1.96 +$ +2.08 +DILUTED EPS: +Income from continuing operations attributed to common stockholders +$ +186,150 +$ +296,945 +$ +320,235 +Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock +144,356 +151,144 +153,871 +Add dilutive effect of potential common shares +947 +555 +1,433 +Weighted average number of diluted common shares outstanding +145,303 +151,699 +155,304 +Diluted income from continuing operations per common share +$ +1.28 +$ +1.96 +$ +2.06 +Diluted loss from discontinued operations per common share +$ +0.00 +$ +0.00 +$ +0.00 +Diluted net income per common share +$ +1.28 +$ +1.96 +$ +2.06 +Potentially dilutive securities excluded as anti-dilutive +2,447 +5,416 +1,641 +Income taxes — The asset and liability method is used in accounting for income taxes. Under +this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and +liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The +effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is +F-10 +Table of Contents +recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized. The Company’s policy is to account for interest and +penalties with respect to income taxes as operating expenses. +Stock-based compensation — The Company recognizes +the cost of share-based payments under the fair-value-based method. Under this method, compensation cost related to share-based payments is measured based on the estimated fair value of the awards at the date of grant, net of estimated forfeitures. +This expense is recognized over the expected life of the awards (See Note 10). +Statement of cash flows — For +purposes of reporting cash flows, cash and cash equivalents include cash on deposit and money market funds. +Recently Issued +Accounting Standards — In February 2013, the FASB issued an accounting standards update that requires additional disclosures regarding reclassifications out of accumulated other comprehensive income. This requirement is effective for fiscal +years, and interim periods within those years, beginning after December 15, 2012, and became effective for the Company in the quarter ended March 31, 2013. The adoption of this update did not have a material impact on the Company’s +disclosures included in its consolidated financial statements. The Company includes in accumulated other comprehensive income the cumulative translation adjustment of its foreign subsidiary. +In February 2013, the FASB issued an accounting standards update to provide guidance for the recognition, measurement, and disclosure of +obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. +The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of +its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are effective during interim and annual periods beginning +after December 15, 2013. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements. +2. +Discontinued Operations +On January 27, 2011, the stock of the Company’s electric wireline subsidiary, Universal Wireline, Inc., was +sold in a cash transaction for $25.5 million. Except for inventory, the working capital of Universal Wireline, Inc. was excluded from the sale and retained by a subsidiary of the Company. Universal Wireline, Inc. was formed in 2010 to acquire an +electric wireline business. The results of operations of this business have been presented as results of discontinued operations in these consolidated financial statements. As of December 31, 2010, the assets to be disposed of were classified +as held for sale. Upon being classified as held for sale, the assets to be disposed of were recorded at fair value less estimated costs to sell resulting in a charge of $2.2 million. Due to the fact that the carrying value of the assets had been +adjusted to net realizable value, no significant additional gain or loss was recognized in connection with the sale. +Summarized operating results from discontinued operations for the year ended December 31, 2011 are shown below (in thousands): +2011 +Operating revenues from discontinued operations +$ +1,104 +Loss from discontinued operations before income taxes +$ +(576 +) +Income tax benefit +209 +Loss from discontinued operations +$ +(367 +) +F-11 +Table of Contents +3. +Property and Equipment +Property and equipment consisted of the following at December 31, 2013 and 2012 (in thousands): +2013 +2012 +Equipment +$ +5,749,975 +$ +5,387,490 +Oil and natural gas properties +183,571 +156,834 +Buildings +80,050 +66,490 +Land +12,054 +10,413 +6,025,650 +5,621,227 +Less accumulated depreciation and depletion +(2,390,109 +) +(2,005,844 +) +Property and equipment, net +$ +3,635,541 +$ +3,615,383 +Depreciation, depletion, amortization and impairment — The following table summarizes +depreciation, depletion, amortization and impairment expense related to property and equipment and intangible assets for 2013, 2012 and 2011 (in thousands): +2013 +2012 +2011 +Depreciation and impairment expense +$ +573,106 +$ +502,953 +$ +419,183 +Amortization expense +3,993 +4,110 +4,110 +Depletion expense +20,370 +19,551 +13,986 +Total +$ +597,469 +$ +526,614 +$ +437,279 +The Company evaluates the recoverability of its long-lived assets whenever events or changes in +circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). In light of levels of activity and revenue per operating day experienced by the Company and its peers in 2011, 2012 and 2013, management +concluded that no triggering event had occurred in 2011, 2012 or 2013 with respect to its contract drilling segment as a whole. The Company also concluded that no triggering event occurred with respect to its pressure pumping segment in 2011, 2012 +or 2013. With respect to the long-lived assets in the Company’s oil and natural gas exploration and production segment, the Company assesses the recoverability of long-lived assets at the end of each quarter due to revisions in its oil and +natural gas reserve estimates and expectations about future commodity prices. +Long-lived assets are evaluated for impairment +at the lowest level for which identifiable cash flows can be separated from other long-lived assets. The Company performs the first step of its impairment assessments by comparing the undiscounted cash flows for each long-lived asset or asset group +to its respective carrying value. The Company’s analysis indicated that the carrying amounts of certain oil and natural gas properties were not recoverable at various testing dates in 2013, 2012 and 2011. The Company’s estimates of +expected future net cash flows from impaired properties are used in measuring the fair value of such properties. The Company recorded impairment charges of $4.0 million, $1.9 million and $3.0 million in 2013, 2012 and 2011, respectively, related to +its oil and natural gas properties. The Company determined the fair value of the impaired assets using internally developed unobservable inputs including future pricing and reserves (level 3 inputs in the fair value hierarchy of fair value +accounting). +On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of +inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer horizontal wells using high +capacity rigs). In connection with the Company’s ongoing planning process, it evaluated its then-current fleet of marketable drilling rigs in 2013, 2012 and 2011 and identified 48, 36 and 53 rigs, during each of those years respectively, that +it determined would no longer be marketed as rigs based on its assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as +F-12 +Table of Contents +well as its assessment of future demand and the suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with +continuing utility to the Company’s other marketed rigs were transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs were retired. The net book values of these assets of $7.9 million in +2013, $5.2 million in 2012 and $15.7 million in 2011 were expensed in the Company’s consolidated statements of operations. +In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, the +Company recorded in its consolidated statement of operations a charge of $29.9 million related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, the Company has lower expectations with respect to +utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. +The Company also evaluates its fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure pumping equipment that would be retired. The net book value +of these assets of $7.3 million was expensed in the Company’s consolidated statements of operations. There were no similar charges in 2013 or 2011. +During 2012, the Company sold its flowback operations in a cash transaction. The sale price was $42.5 million and the Company recognized a gain on disposal of $22.6 million. Also during 2012, the +Company sold at auction certain excess drilling assets. The total sale price was $10.6 million, and the Company recognized a gain on disposal of $4.5 million. +4. +Goodwill and Intangible Assets +Goodwill — Goodwill by operating segment as of December 31, 2013 and 2012 and changes for the years +then ended are as follows (in thousands): +Contract +Drilling +Pressure +Pumping +Total +Balance December 31, 2011 +$ +86,234 +$ +67,575 +$ +153,809 +Changes to goodwill +— +— +— +Balance December 31, 2012 +86,234 +67,575 +153,809 +Changes to goodwill +— +— +— +Balance December 31, 2013 +$ +86,234 +$ +67,575 +$ +153,809 +There were no accumulated impairment losses as of December 31, 2013 or 2012. +Goodwill is evaluated at least annually on December 31, or when circumstances require, to determine if the fair value of recorded +goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments. The +Company first determines whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a +two-step impairment test. From time to time, the Company may perform the first step of quantitative testing for goodwill impairment in lieu of performing a qualitative assessment. The first step is to compare the fair value of an entity’s +reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is +allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment +loss would be recognized in the amount of the shortfall. +In connection with its annual goodwill impairment assessment as of +December 31, 2012, the Company determined based on an assessment of qualitative factors that it was more likely than not that the fair values of +F-13 +Table of Contents +the Company’s reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, the Company considered the continued demand +experienced during 2012 for its services in the contract drilling and pressure pumping businesses. The Company also considered the then current and expected levels of commodity prices for crude oil and natural gas, which influence its overall level +of business activity in these operating segments. Additionally, operating results for 2012 and forecasted operating results for 2013 were also taken into account. The Company’s overall market capitalization and the large amount of calculated +excess of the fair values of the Company’s reporting units over their carrying values and lack of significant changes in the key assumptions from its 2010 quantitative Step 1 assessment of goodwill were also considered. +The Company performed a quantitative impairment assessment of its goodwill as of December 31, 2013. In completing the first step of +the analysis, the Company used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting units. In developing this fair value estimate, the Company +applied key assumptions including an assumed discount rate of 11.87% for the contract drilling reporting unit and an assumed discount rate of 12.40% for the pressure pumping reporting unit. An assumed long-term growth rate of 3.00% was used for both +reporting units. Based on the results of the first step of the impairment test in 2013, the Company concluded that no impairment was indicated in its contract drilling or pressure pumping reporting units as the estimated fair value of each reporting +unit exceeded its carrying value. +The Company has undertaken extensive efforts in the past several years to upgrade its fleet +of equipment and believes that it is well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical +wells that has resulted primarily from low natural gas prices. In the event that market conditions weaken, the Company may be required to record an impairment of goodwill in its contract drilling or pressure pumping reporting units in the future, +and such impairment could be material. +Intangible Assets — Intangible assets were recorded in the pressure pumping +operating segment in connection with the fourth quarter 2010 acquisition of the assets of a pressure pumping business. As a result of the purchase price allocation, the Company recorded intangible assets related to a non-compete agreement and the +customer relationships acquired. These intangible assets were recorded at fair value on the date of acquisition. +The +non-compete agreement had a term of three years from October 1, 2010. The value of this agreement was estimated using a with and without scenario where cash flows were projected through the term of the agreement assuming the agreement is in +place and compared to cash flows assuming the non-compete agreement was not in place. The intangible asset associated with the non-compete agreement was amortized on a straight-line basis over the three-year term of the agreement. Amortization +expense of $350,000, $467,000 and $467,000 was recorded in the years ended December 31, 2013, 2012 and 2011, respectively, associated with the non-compete agreement. +The value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the +time of the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of $3.6 million was recorded in each of the years ended +December 31, 2013, 2012 and 2011, associated with customer relationships. +For both the non-compete agreement and the +customer relationships, the Company concluded no triggering events necessitating an impairment assessment had occurred in 2013, 2012 or 2011. +F-14 +Table of Contents +The following table presents the gross carrying amount and accumulated amortization of +intangible assets as of December 31, 2013 and 2012 (in thousands): +2013 +2012 +Gross +Carrying +Amount +Accumulated +Amortization +Net +Carrying +Amount +Gross +Carrying +Amount +Accumulated +Amortization +Net +Carrying +Amount +Non-compete agreement +$ +1,400 +$ +(1,400 +) +$ +— +$ +1,400 +$ +(1,050 +) +$ +350 +Customer relationships +25,500 +(11,839 +) +13,661 +25,500 +(8,196 +) +17,304 +Total intangible assets +$ +26,900 +$ +(13,239 +) +$ +13,661 +$ +26,900 +$ +(9,246 +) +$ +17,654 +5. +Accrued Expenses +Accrued expenses consisted of the following at December 31, 2013 and 2012 (in thousands): +2013 +2012 +Salaries, wages, payroll taxes and benefits +$ +45,836 +$ +55,430 +Workers’ compensation liability +74,975 +68,441 +Property, sales, use and other taxes +12,367 +9,749 +Insurance, other than workers’ compensation +10,129 +10,419 +Accrued interest payable +7,604 +7,664 +Deferred revenue — current +— +1,523 +Other +9,546 +5,406 +$ +160,457 +$ +158,632 +Deferred revenue was recorded in 2010 in the purchase price allocation associated with the Company’s +acquisition of a pressure pumping business. The deferred revenue related to out-of-market pricing agreements that were in place at the acquired business at the time of the acquisition. The deferred revenue was recognized as pressure pumping revenue +over the remaining term of the pricing agreements, which have now expired. Deferred revenue of approximately $1.5 million, $7.2 million and $8.4 million was recognized in the years ended December 31, 2013, 2012 and 2011, respectively, related +to these pricing agreements. +6. +Asset Retirement Obligation +The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and +natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement +obligations during 2013 and 2012 (in thousands): +2013 +2012 +Balance at beginning of year +$ +4,422 +$ +3,455 +Liabilities incurred +375 +418 +Liabilities settled +(126 +) +(150 +) +Accretion expense +166 +163 +Revision in estimated costs of plugging oil and natural gas wells +— +536 +Asset retirement obligation at end of year +$ +4,837 +$ +4,422 +F-15 +Table of Contents +7. +Long Term Debt +Credit Facilities — On August 19, 2010, the Company entered into a committed senior unsecured Credit +Agreement (the “2010 Credit Agreement”) which included a revolving credit facility that permitted aggregate borrowings of up to $400 million and a $100 million term loan facility. The term loan facility was fully drawn on August 19, +2010. The term loan facility was payable in quarterly principal installments commencing November 10, 2010. The installment amounts were scheduled to vary from 1.25% of the original principal amount for each of the first four quarterly +installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments and 5.00% of the original principal amount for the next subsequent three quarterly installments, with the balance due on the maturity date +of August 19, 2014. The outstanding balance of the term loan facility was paid in full on June 14, 2012. +On +September 27, 2012, the Company entered into a Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party +thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced the 2010 Credit Agreement. +The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility +contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time. +The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced +December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% +of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments. +Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 +million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility. +Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, +that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon +the Company’s debt to capitalization ratio. As of December 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by the Company equal to the +applicable margin for LIBOR rate loans times the amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%. +Each domestic subsidiary of the Company other than immaterial subsidiaries has unconditionally guaranteed all existing and future +indebtedness and liabilities of the other guarantors and the Company arising under the Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate +swap contract with any person while such person is a lender under the Credit Agreement. +The Credit Agreement requires +compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness +to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last +day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal +quarters to interest charges for +F-16 +Table of Contents +the same period. The Company was in compliance with these covenants at December 31, 2013. The Credit Agreement also contains customary representations, warranties and affirmative and +negative covenants. +Events of default under the Credit Agreement include failure to pay principal or interest when due, +failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is +continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document +(provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit. +As of December 31, 2013, the Company had $92.5 million principal amount outstanding under the term loan facility at an interest rate +of 2.50% and no amounts outstanding under the revolving credit facility. The Company had $39.8 million in letters of credit outstanding at December 31, 2013 and, as a result, had available borrowing capacity of approximately $460 million at +that date. +Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in +aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The Company will pay interest on the +Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020. +On +June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amounts of its 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear +interest at a rate of 4.27% per annum. The Company will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022. +The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all +other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries. +The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a +partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the +prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes +upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus +accrued and unpaid interest thereon to the prepayment date. +The respective note purchase agreements require compliance with +two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money +indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as +of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. The +Company was in compliance with these covenants at December 31, 2013. +Events of default under the note purchase agreements +include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence +of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective +F-17 +Table of Contents +notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, +the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable. +The Company incurred approximately $10.8 million in debt issuance costs during 2010 in connection with the 2010 Credit Agreement and the Series A Notes. The Company incurred approximately $7.6 million in +debt issuance costs during 2012 in connection with the Series B Notes and the Credit Agreement. These costs were deferred and are recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of +debt issuance costs for the 2010 Credit Agreement, the Series A Notes, the Series B Notes and the Credit Agreement was approximately $2.2 million, $3.4 million and $2.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. +The amount for the year ended December 31, 2012 includes $978,000 of costs related to the early termination of the 2010 Credit Agreement. +Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2013 (in thousands): +Year ending December 31, +2014 +$ +10,000 +2015 +12,500 +2016 +28,750 +2017 +41,250 +2018 +— +Thereafter +600,000 +Total +$ +692,500 +8. +Commitments, Contingencies and Other Matters +Commitments — As of December 31, 2013, the Company maintained letters of credit in the aggregate +amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire +annually at various times during the year and are typically renewed. As of December 31, 2013, no amounts had been drawn under the letters of credit. +As of December 31, 2013, the Company had commitments to purchase approximately $225 million of major equipment for its drilling and pressure pumping businesses. +The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from +certain vendors. These agreements expire in 2016 and 2017. As of December 31, 2013, the remaining obligation under these agreements was approximately $25.2 million, of which materials with a total purchase price of approximately $7.7 million +are expected to be delivered during 2014. In the event that the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall. +In November 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance up +to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made +through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2013, advances of approximately $11.8 million had been made under this agreement +and repayments of approximately $2.6 had been received resulting in a balance outstanding of approximately $9.2 million. +Contingencies — In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related +to certain of its employment practices. The cause findings relate to allegations that the Company tolerated a hostile work environment for employees based on national origin and race. The cause +F-18 +Table of Contents +findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. The Company and the EEOC are engaged in the +statutory conciliation process. If such conciliation process is unsuccessful, the Company believes that litigation will ensue. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, +the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter. +The Company’s operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including +inclement weather, blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant +environmental and reservoir damages. These risks could expose the Company to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. +Any contractual right to indemnification that the Company may have for any such risk, may be unenforceable or limited due to negligent or +willful acts of commission or omission by the Company, its subcontractors and/or suppliers. The Company’s customers may dispute, or be unable to meet, their contractual indemnification obligations to the Company due to financial, legal or other +reasons. Accordingly, the Company may be unable to transfer these risks to its customers by contract or indemnification agreements. Incurring a liability for which the Company is not fully indemnified or insured could have a material adverse effect +on its business, financial condition, cash flows and results of operations. +The Company has insurance coverage for +comprehensive general liability, automobile liability, workers’ compensation and employer’s liability, and certain other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased +deductibles on certain insurance policies. For example, the Company generally maintains a $1.0 million per occurrence deductible on its workers’ compensation and equipment insurance coverages and a $2.0 million per occurrence self-insured +retention on its general liability and automobile liability insurance coverage. The Company self-insures a number of other risks, including loss of earnings and business interruption, and does not carry a significant amount of insurance to cover +risks of underground reservoir damage. If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on the Company’s +business, financial condition, cash flows and results of operations. Accrued expenses related to insurance claims are set forth in Note 5. +The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, +will have a material adverse effect on its financial condition, results of operations or cash flows. +Other Matters +— The Company has Change in Control Agreements with its Chairman of the Board, Chief Executive Officer, two Senior Vice Presidents and its General Counsel (the “Key Employees”). Each Change in Control Agreement generally has an +initial term with automatic twelve-month renewals unless the Company notifies the Key Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the +term of the agreement and the Key Employee’s employment is terminated (i) by the Company other than for cause or other than automatically as a result of death, disability or retirement, or (ii) by the Key Employee for good reason (as +those terms are defined in the Change in Control Agreements), then the Key Employee shall generally be entitled to, among other things: +• +a bonus payment equal to the highest bonus paid after the Change in Control Agreement was entered into (such bonus payment for each Key Employee +prorated for the portion of the fiscal year preceding the termination date); +• +a payment equal to 2.5 times (in the case of the Chairman of the Board and Chief Executive Officer), 2 times (in the case of the Senior Vice +Presidents) or 1.5 times (in the case of the General Counsel) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three +F-19 +Table of Contents +annual bonuses earned by the Key Employee for the three fiscal years preceding the termination date (or a benchmark bonus in the case of the Chief Executive Officer); and +• +continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board and Chief Executive Officer) +or two years (in the case of the Senior Vice Presidents and General Counsel). +Other than with respect to the +Chief Executive Officer, each Change in Control Agreement provides the Key Employee with a full gross-up payment for any excise taxes imposed on payments and benefits received under the Change in Control Agreements or otherwise, including other +taxes that may be imposed as a result of the gross-up payment. +9. +Stockholders’ Equity +Cash Dividends — The Company paid cash dividends during the years ended December 31, 2011, 2012 and +2013 as follows: +Per Share +Total +(in thousands) +2011: +Paid on March 30, 2011 +$ +0.05 +$ +7,708 +Paid on June 30, 2011 +0.05 +7,772 +Paid on September 30, 2011 +0.05 +7,777 +Paid on December 30, 2011 +0.05 +7,788 +Total cash dividends +$ +0.20 +$ +31,045 +2012: +Paid on March 30, 2012 +$ +0.05 +$ +7,788 +Paid on June 29, 2012 +0.05 +7,650 +Paid on September 28, 2012 +0.05 +7,518 +Paid on December 28, 2012 +0.05 +7,346 +Total cash dividends +$ +0.20 +$ +30,302 +2013: +Paid on March 29, 2013 +$ +0.05 +$ +7,312 +Paid on June 28, 2013 +0.05 +7,361 +Paid on September 30, 2013 +0.05 +7,231 +Paid on December 31, 2013 +0.05 +7,208 +Total cash dividends +$ +0.20 +$ +29,112 +On February 5, 2014, the Company’s Board of Directors approved a cash dividend on its common stock in +the amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend +upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors. +On August 1, 2007, the Company’s Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of the Company’s common stock in open market or privately +negotiated transactions. On July 25, 2012, the Company’s Board of Directors terminated the remaining authority under the 2007 stock buyback program, and approved a new stock buyback program authorizing purchases of up to $150 million +of common stock in open market or privately negotiated transactions. On September 6, 2013, the +F-20 +Table of Contents +Company’s Board of Directors terminated any remaining authority under the 2012 stock buyback program, and approved a new stock buyback program that authorizes purchase of up to $200 million +of the Company’s common stock in open market or privately negotiated transactions. As of December 31, 2013, the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under +the new stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock. +The Company +acquired shares of stock from employees during 2013, 2012 and 2011 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options by employees. The +remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market value. +These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) and not pursuant to the stock buyback program. +Treasury stock acquisitions during the years ended December 31, 2013, 2012 and 2011 were as follows (dollars in thousands): +2013 +2012 +2011 +Shares +Cost +Shares +Cost +Shares +Cost +Treasury shares at beginning of period +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +27,343,814 +$ +620,445 +Purchases pursuant to stock buyback programs: +2007 program +— +— +4,708,784 +70,092 +8,689 +255 +2012 program +2,567,266 +51,107 +5,863,451 +98,892 +— +— +2013 program +602,564 +12,517 +— +— +— +— +Acquisitions Pursuant to the 2005 Long-Term Incentive Plan +951,489 +22,213 +86,932 +1,308 +135,068 +4,059 +Treasury shares at end of period +42,268,057 +$ +880,888 +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +10. +Stock-based Compensation +The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the +cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance +conditions. The Company’s share-based awards have also included both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as liability awards. Share-settled performance unit awards are +accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest. +The Company’s shareholders have approved the 2005 Plan, and the Board of Directors adopted a resolution that no future grants would +be made under any of the Company’s other previously existing plans. The Company’s share-based compensation plans at December 31, 2013 follow: +Plan Name +Shares +Authorized +for Grant +Awards +Outstanding +Shares +Available +for Grant +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended +15,250,000 +8,026,643 +274,071 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”) +— +810,000 +— +F-21 +Table of Contents +A summary of the 2005 Plan follows: +• +The Compensation Committee of the Board of Directors administers the plan. +• +All employees, officers and directors are eligible for awards. +• +The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and three +years for employees. +• +The Compensation Committee sets the term of awards and no option term can exceed 10 years. +• +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. As of December 31, 2013, non-incentive stock options, restricted stock awards, restricted stock units and performance unit awards +had been granted under the plan. +Options granted under the 1997 Plan typically vested over three or five +years as dictated by the Compensation Committee. These options have terms of no more than ten years. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant. Restricted stock +awards granted under the 1997 Plan typically vested over four years. +Stock Options — The Company estimates the +grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the +options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the +options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the years ended +December 31, 2013, 2012 and 2011 follow: +2013 +2012 +2011 +Volatility +41.36 +% +48.79 +% +45.97 +% +Expected term (in years) +5.00 +5.00 +5.00 +Dividend yield +0.89 +% +1.21 +% +0.67 +% +Risk-free interest rate +0.70 +% +0.87 +% +2.34 +% +Stock option activity for the year ended December 31, 2013 follows: +Shares +Weighted-average +exercise price +Outstanding at beginning of year +7,827,195 +$ +20.35 +Granted +692,500 +$ +22.51 +Exercised +(1,190,000 +) +$ +16.21 +Cancelled +(10,000 +) +$ +18.63 +Expired +— +— +Outstanding at end of year +7,319,695 +$ +21.23 +Exercisable at end of year +6,250,860 +$ +21.29 +During 2013, the Company acquired 637,624 shares of treasury stock from employees upon the exercise of +stock options. Shares having a market value of $12.3 million were withheld from employees and added to treasury stock to satisfy the exercise price in connection with the exercise of the stock options. Shares having a +F-22 +Table of Contents +market value of $2.9 million were withheld from employees and added to treasury stock to satisfy payroll tax withholding obligations upon the exercise of the stock options. +Options outstanding at December 31, 2013 have an aggregate intrinsic value of approximately $37 million and a weighted-average +remaining contractual term of 5.10 years. Options exercisable at December 31, 2013 have an aggregate intrinsic value of approximately $32 million and a weighted-average remaining contractual term of 4.45 years. Additional information with +respect to options granted, vested and exercised during the years ended December 31, 2013, 2012 and 2011 follows: +2013 +2012 +2011 +Weighted-average grant date fair value of stock options granted (per share) +$ +7.59 +$ +6.37 +$ +12.24 +Aggregate grant date fair value of stock options vested during the year (in thousands) +$ +5,240 +$ +5,512 +$ +5,639 +Aggregate intrinsic value of stock options exercised (in thousands) +$ +8,683 +$ +138 +$ +12,663 +As of December 31, 2013, options to purchase 1.1 million shares were outstanding and not vested. +All of these non-vested options are expected to ultimately vest. Additional information as of December 31, 2013 with respect to these non-vested options follows: +Aggregate intrinsic value +$5.0 million +Weighted-average remaining contractual term +8.90 years +Weighted-average remaining expected term +3.90 years +Weighted-average remaining vesting period +1.81 years +Unrecognized compensation cost +$6.3 million +Restricted Stock — For all restricted stock awards to date, shares of common stock were issued +when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. The Company +uses the straight-line method to recognize periodic compensation cost over the vesting period. +Restricted stock activity for +the year ended December 31, 2013 follows: +Shares +Weighted- +average Grant +Date Fair Value +Non-vested restricted stock outstanding at beginning of year +1,279,146 +$ +20.03 +Granted +954,750 +$ +21.66 +Vested +(653,636 +) +$ +20.56 +Forfeited +(83,568 +) +$ +20.04 +Non-vested restricted stock outstanding at end of year +1,496,692 +$ +20.84 +As of December 31, 2013, approximately 1.4 million shares of non-vested restricted stock +outstanding are expected to vest. Additional information as of December 31, 2013 with respect to these non-vested shares follows: +Aggregate intrinsic value +$35.5 million +Weighted-average remaining vesting period +1.94 years +Unrecognized compensation cost +$22.5 million +Restricted Stock Units — For all restricted stock unit awards made to date, shares of common +stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units. The Company uses the +straight-line method to recognize periodic compensation cost over the vesting period. +F-23 +Table of Contents +Restricted stock unit activity for the year ended December 31, 2013 follows: +Shares +Weighted- +average +Grant Date +Fair Value +Non-vested restricted stock units outstanding at beginning of year +17,670 +$ +20.08 +Granted +11,250 +$ +21.09 +Vested +(8,664 +) +$ +20.01 +Forfeited +— +— +Non-vested restricted stock units outstanding at end of year +20,256 +$ +20.67 +Performance Unit Awards. In 2009, the Company granted cash-settled +performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provided for those executive officers to receive a cash payment upon the achievement of certain performance goals established +by the Compensation Committee during a specified period. The performance period for the 2009 Performance Units was the period from April 1, 2009 through March 31, 2012. The performance goals for the 2009 Performance Units were tied to the +Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. These goals were considered to be market conditions under the relevant accounting +standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients would receive a target payment if the Company’s total shareholder return was positive and, when +compared to the peer group, was at or above the 50 th +percentile but less than the 75 th percentile and two times +the target if at the 75 th percentile or higher. If the +Company’s total shareholder return was positive, and, when compared to the peer group, was at or above the +25 th percentile but less than the 50 th percentile, the recipients would only receive one-half of the target +payment. The total target amount with respect to the 2009 Performance Units was approximately $3.4 million. Because the 2009 Performance Units were settled in cash at the end of the performance period, they were accounted for as liability awards and +the Company’s pro-rated obligation was measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. The performance period ended on March 31, 2012 and the Company’s total shareholder +return was at the 46 th percentile. The resulting cash +payments totaling $1.7 million were paid in April 2012. For the year ended December 31, 2012, a compensation benefit of approximately $1.9 million was recognized. For the year ended December 31, 2011, compensation expense associated +with the 2009 Performance Units was approximately $1.3 million. +In 2010, 2011, 2012 and 2013, the Company +granted stock-settled performance unit awards to certain executive officers (the “Stock-Settled Performance Units”). The Stock-Settled Performance Units provide for the recipients to receive a grant of shares of stock upon the achievement +of certain performance goals established by the Compensation Committee during a specified period. The performance period for the Stock-Settled Performance Units is the three year period commencing on April 1 of the year of grant, but can extend +for an additional two years in certain circumstances. The performance goals for the Stock-Settled Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer +group determined by the Compensation Committee. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the respective performance +units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 50 th percentile and two times the target if at the 75 th percentile or higher. If the Company’s total shareholder return is positive, and, when compared to the peer +group, is at the 25 th percentile, the recipients will only +receive one-half of the target number of shares. The grant of shares when achievement is between the 25 th and 75 th +percentile will be determined on a pro-rata basis. The performance period for the 2010 Stock-Settled Performance Units ended on March 31, 2013, and the Company’s total shareholder return was at the 93 rd percentile. In April 2013, 357,500 +F-24 +Table of Contents +shares were issued to settle the 2010 Stock-Settled Performance Units. The total target number of shares with respect to the Stock-Settled Performance Units is set forth below: +2013 +Performance +Unit Awards +2012 +Performance +Unit Awards +2011 +Performance +Unit Awards +2010 +Performance +Unit Awards +Target number of shares +236,500 +192,000 +144,375 +178,750 +Because the Stock-Settled Performance Units are stock-settled awards, they are accounted for as equity +awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Stock-Settled Performance Units is set forth below (in thousands): +2013 +Performance +Unit Awards +2012 +Performance +Unit Awards +2011 +Performance +Unit Awards +2010 +Performance +Unit Awards +Aggregate fair value at date of grant +$ +5,564 +$ +3,065 +$ +5,569 +$ +3,117 +These fair value amounts are charged to expense on a straight-line basis over the performance period. +Compensation expense associated with the Stock-Settled Performance Units is set forth below (in thousands): +2013 +Performance +Unit Awards +2012 +Performance +Unit Awards +2011 +Performance +Unit Awards +2010 +Performance +Unit Awards +Year ended December 31, 2013 +$ +1,391 +$ +1,022 +$ +1,856 +$ +260 +Year ended December 31, 2012 +NA +766 +$ +1,856 +$ +1,039 +Year ended December 31, 2011 +NA +NA +$ +1,392 +$ +1,039 +Dividends on Equity Awards — Non-forfeitable cash dividends are paid on restricted stock +awards and dividend equivalents are paid on restricted stock units. These payments are recognized as follows: +• +Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest. +• +Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do +not vest. +• +Dividend equivalents are recognized as additional compensation cost for restricted stock units. +11. +Leases +The Company incurred rent expense of $47.4 million, $39.0 million and $35.0 million for the years ended +December 31, 2013, 2012 and 2011, respectively. Rent expense is primarily related to short-term equipment rentals that are generally passed through to customers. The Company’s obligations under non-cancelable operating lease agreements are +not material to its operations or cash flows. +F-25 +Table of Contents +12. +Income Taxes +Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended +December 31, 2013, 2012 and 2011 are as follows (in thousands): +2013 +2012 +2011 +Federal income tax expense (benefit): +Current +$ +41,558 +$ +(512 +) +$ +16,336 +Deferred +47,136 +156,003 +146,842 +88,694 +155,491 +163,178 +State income tax expense: +Current +11,733 +12,455 +6,056 +Deferred +4,229 +5,483 +13,196 +15,962 +17,938 +19,252 +Foreign income tax expense (benefit): +Current +4,572 +3,817 +6,579 +Deferred +(796 +) +(1,050 +) +(1,071 +) +3,776 +2,767 +5,508 +Total income tax expense: +Current +57,863 +15,760 +28,971 +Deferred +50,569 +160,436 +158,967 +Total income tax expense: +$ +108,432 +$ +176,196 +$ +187,938 +The difference between the statutory federal income tax rate and the effective income tax rate for the +years ended December 31, 2013, 2012 and 2011 is summarized as follows: +2013 +2012 +2011 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +3.7 +2.5 +2.5 +Permanent differences +(1.5 +) +(0.2 +) +(0.1 +) +Other, net +(0.6 +) +(0.3 +) +(0.6 +) +Effective tax rate +36.6 +% +37.0 +% +36.8 +% +The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 +(as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent difference for 2011 does not include any +deduction as it is limited to taxable income and the Company had a tax loss in 2011. The permanent difference for 2012 does not include any deduction as it is limited to taxable income and the Company did not have taxable income in 2012 due to the +utilization of net operating loss carryforwards. The permanent difference for 2013 includes a deduction of $10.0 million as the Company fully utilized its remaining net operating loss carryforwards. +F-26 +Table of Contents +The tax effect of significant temporary differences representing deferred tax assets and +liabilities and changes therein were as follows (in thousands): +December +31, +2013 +Net +Change +December +31, +2012 +Net +Change +December +31, +2011 +Net +Change +December +31, +2010 +Deferred tax assets: +Current: +Net operating loss carryforwards +$ +— +$ +(18,914 +) +$ +18,914 +$ +(95,662 +) +$ +114,576 +$ +114,576 +$ +— +Workers’ compensation allowance +27,612 +2,534 +25,078 +1,074 +24,004 +714 +23,290 +Other +19,647 +(804 +) +20,451 +1,651 +18,800 +146 +18,654 +47,259 +(17,184 +) +64,443 +(92,937 +) +157,380 +115,436 +41,944 +Non-current: +Net operating loss carryforwards +13,452 +1,690 +11,762 +(6,672 +) +18,434 +11,969 +6,465 +Expense associated with employee stock options +16,208 +1,536 +14,672 +1,944 +12,728 +1,476 +11,252 +Federal benefit of state deferred tax liabilities +22,838 +816 +22,022 +1,762 +20,260 +7,105 +13,155 +Other +14,703 +(421 +) +15,124 +4,454 +10,670 +(5,361 +) +16,031 +67,201 +3,621 +63,580 +1,488 +62,092 +15,189 +46,903 +Total deferred tax assets +114,460 +(13,563 +) +128,023 +(91,449 +) +219,472 +130,625 +88,847 +Deferred tax liabilities: +Current: +Other +(14,307 +) +(2,823 +) +(11,484 +) +3,171 +(14,655 +) +474 +(15,129 +) +Non-current: +Property and equipment basis difference +(939,594 +) +(33,997 +) +(905,597 +) +(69,774 +) +(835,823 +) +(289,168 +) +(546,655 +) +Other +(15,471 +) +(186 +) +(15,285 +) +(2,384 +) +(12,901 +) +(1,231 +) +(11,670 +) +(955,065 +) +(34,183 +) +(920,882 +) +(72,158 +) +(848,724 +) +(290,399 +) +(558,325 +) +Total deferred tax liabilities +(969,372 +) +(37,006 +) +(932,366 +) +(68,987 +) +(863,379 +) +(289,925 +) +(573,454 +) +Net deferred tax liability +$ +(854,912 +) +$ +(50,569 +) +$ +(804,343 +) +$ +(160,436 +) +$ +(643,907 +) +$ +(159,300 +) +$ +(484,607 +) +In assessing the realizability of deferred tax assets, management considers whether it is more likely than +not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become +deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company expects the deferred tax assets at December 31, 2013 and +2012 to be realized as a result of the reversal of existing taxable temporary differences giving rise to deferred tax liabilities and the generation of taxable income; therefore, no valuation allowance is considered necessary. +Other deferred tax assets consist primarily of the tax effect of various allowance accounts and tax-deferred expenses expected to generate +future tax benefits of approximately $34.4 million. Other deferred tax liabilities consist primarily of the tax effect of receivables from insurance companies and tax-deferred income not yet recognized for tax purposes. +F-27 +Table of Contents +For income tax purposes, the Company has approximately $177 million of state net operating +losses that can be carried forward as of December 31, 2013. The state net operating losses that can be carried forward, if unused, are scheduled to expire as follows: 2015 — $260,000; 2016 — $8.3 million; 2025 — $1.6 million: +2026 — $6.0 million; 2028 — $12.7 million; 2029 — $33.7 million; 2030 — $26.2 million and 2031 — $88.2 million. +As of December 31, 2013, the Company had no unrecognized tax benefits. The Company has established a policy to account for interest and penalties related to uncertain income tax positions as +operating expenses. As of December 31, 2013, the tax years ended December 31, 2010 through December 31, 2012 are open for examination by U.S. taxing authorities. As of December 31, 2013, the tax years ended December 31, 2009 +through December 31, 2012 are open for examination by Canadian taxing authorities. +On January 1, 2010, the Company +converted its Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 +million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets. +As a result of the above conversion, the Company’s Canadian assets are no longer directly subject to United States taxation, provided +that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and intends to do so for the foreseeable future. As a +result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $38.5 million as of December 31, 2013. The unrecognized deferred tax liability associated with +these earnings was approximately $5.9 million, net of available foreign tax credits. This liability would be recognized if the Company received a dividend of the unremitted earnings. +13. +Employee Benefits +The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses +of approximately $6.2 million in 2013, $5.4 million in 2012 and $4.6 million in 2011 for the Company’s contributions to the plan. +14. +Business Segments +The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business +segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a +distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for +purposes of determining resource allocation and assessing performance. As discussed in Note 2, in January 2011, the Company exited the electric wireline business. Operating results for that business for the year ended December 31, 2011 is +presented as discontinued operations in the consolidated statements of operations. +Contract Drilling — The Company +markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2013, the Company had 279 marketable land-based drilling rigs in the continental United States, Alaska and western and northern +Canada. +For the years ended December 31, 2013, 2012 and, 2011, contract drilling revenue earned in Canada was $86.6 +million, $79.4 million and $106 million, respectively. Additionally, long-lived assets within the contract drilling segment located in Canada totaled $69.1 million and $72.6 million as of December 31, 2013 and 2012, respectively. +Pressure Pumping — The Company provides pressure pumping services to oil and natural gas operators primarily in Texas and the +Appalachian region. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Well stimulation involves +F-28 +Table of Contents +processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. Cementing is the process of inserting material between the hole and the pipe +to center and stabilize the pipe in the hole. +Oil and Natural Gas — The Company owns and invests in oil and +natural gas assets as a non-operating working interest owner. The Company’s oil and natural gas interests are located primarily in Texas and New Mexico. +Major Customer — During 2013, one customer accounted for approximately $286 million or 10.5% of the Company’s consolidated operating revenues. These revenues were earned in both the +Company’s contract drilling and pressure pumping businesses. No single customer accounted for 10% or more of consolidated operating revenues in 2012 or 2011. +F-29 +Table of Contents +The following tables summarize selected financial information relating to the Company’s +business segments (in thousands): +Years Ended December 31, +2013 +2012 +2011 +Revenues: +Contract drilling +$ +1,684,878 +$ +1,826,519 +$ +1,673,629 +Pressure pumping +979,166 +841,771 +845,803 +Oil and natural gas +57,257 +59,930 +50,559 +Total segment revenues +2,721,301 +2,728,220 +2,569,991 +Elimination of intercompany revenues(a) +(5,267 +) +(4,806 +) +(4,048 +) +Total revenues +$ +2,716,034 +$ +2,723,414 +$ +2,565,943 +Income from continuing operations before income taxes: +Contract drilling +$ +266,262 +$ +349,393 +$ +346,083 +Pressure pumping +87,244 +132,795 +193,440 +Oil and natural gas +19,948 +27,210 +23,982 +373,454 +509,398 +563,505 +Corporate and other +(54,647 +) +(45,843 +) +(42,903 +) +Net gain on asset disposals(b) +3,384 +33,806 +4,999 +Interest income +918 +554 +187 +Interest expense +(28,359 +) +(22,750 +) +(15,652 +) +Other +1,691 +508 +582 +Income from continuing operations before income taxes +$ +296,441 +$ +475,673 +$ +510,718 +Identifiable assets: +Contract drilling +$ +3,569,588 +$ +3,538,289 +$ +3,252,116 +Pressure pumping +761,199 +784,128 +748,643 +Oil and natural gas +58,656 +54,188 +44,990 +Corporate and other(c) +297,684 +180,306 +176,152 +Total assets +$ +4,687,127 +$ +4,556,911 +$ +4,221,901 +Depreciation, depletion, amortization and impairment: +Contract drilling +$ +438,728 +$ +390,316 +$ +344,312 +Pressure pumping +129,984 +111,062 +73,279 +Oil and natural gas +24,400 +21,417 +16,962 +Corporate and other +4,357 +3,819 +2,726 +Total depreciation, depletion, amortization and impairment +$ +597,469 +$ +526,614 +$ +437,279 +Capital expenditures: +Contract drilling +$ +504,508 +$ +744,949 +$ +784,686 +Pressure pumping +122,782 +194,117 +198,061 +Oil and natural gas +31,245 +29,888 +22,884 +Corporate and other +3,926 +5,034 +5,947 +Total capital expenditures +$ +662,461 +$ +973,988 +$ +1,011,578 +(a) +Includes contract drilling intercompany revenues related to drilling services provided to the oil and natural gas exploration and production segment. +F-30 +Table of Contents +(b) +Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or +losses have been separately presented and excluded from the results of specific segments. +(c) +Corporate and other assets primarily include cash on hand and certain deferred tax assets. +15. +Concentrations of Credit Risk +Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of +demand deposits, temporary cash investments and trade receivables. +The Company believes it has placed its demand deposits and +temporary cash investments with high credit-quality financial institutions. At December 31, 2013 and 2012, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands): +2013 +2012 +Deposits in FDIC and SIPC-insured institutions under insurance limits +$ +369 +$ +270 +Deposits in FDIC and SIPC-insured institutions over insurance limits +269,314 +161,195 +Deposits in foreign banks +20,921 +22,511 +290,604 +183,976 +Less outstanding checks and other reconciling items +(41,095 +) +(73,253 +) +Cash and cash equivalents +$ +249,509 +$ +110,723 +Concentrations of credit risk with respect to trade receivables are primarily focused on companies +involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides services. As is general industry practice, the Company +typically does not require customers to provide collateral. No significant losses from individual customers were experienced during the years ended December 31, 2013, 2012 or 2011. The Company recognized a $1.1 million provision for bad debts +in 2012. No provision for bad debts was recognized in 2013 or in 2011. +16. +Fair Values of Financial Instruments +The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to +the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. +The estimated fair value of the Company’s outstanding debt balances (including current portion) as of December 31, 2013 and 2012 is set forth below (in thousands): +December 31, 2013 +December 31, 2012 +Carrying +Value +Fair +Value +Carrying +Value +Fair +Value +Borrowings under credit agreements: +Term loan facilities +$ +92,500 +$ +92,500 +$ +98,750 +$ +98,750 +4.97% Series A Senior Notes +300,000 +304,293 +300,000 +329,281 +4.27% Series B Senior Notes +300,000 +286,772 +300,000 +310,591 +Total debt +$ +692,500 +$ +683,565 +$ +698,750 +$ +738,622 +The carrying values of the balances outstanding under the term loan approximate their fair values as this +instrument has a floating interest rate. The fair values of the Series A Notes and Series B Notes at December 31, 2013 and 2012 are based on discounted cash flows associated with the respective notes using current market rates of interest at +those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.52% at December 31, 2013 and 3.36% at December 31, 2012. For the Series B Notes, the current +F-31 +Table of Contents +market rates used in measuring this fair value were 4.89% at December 31, 2013 and 3.70% at December 31, 2012. These fair value estimates are based on observable market inputs and are +considered Level 2 fair value estimates in the fair value hierarchy of fair value accounting. +17. +Quarterly Financial Information (in thousands, except per share amounts) (unaudited) +1 st +Quarter +2 nd +Quarter +3rd Quarter +4th Quarter +2012 +Operating revenues +$ +745,921 +$ +681,112 +$ +643,631 +$ +652,750 +Operating income +157,664 +150,894 +88,594 +100,209 +Net income +97,274 +92,538 +50,806 +58,859 +Net income per common share: +Basic +$ +0.62 +$ +0.60 +$ +0.34 +$ +0.40 +Diluted +$ +0.62 +$ +0.60 +$ +0.33 +$ +0.40 +2013 +Operating revenues +$ +667,039 +$ +659,316 +$ +730,907 +$ +658,772 +Operating income +94,932 +70,606 +124,551 +32,102 +Net income +56,230 +40,768 +74,420 +16,591 +Net income per common share: +Basic +$ +0.38 +$ +0.28 +$ +0.51 +$ +0.12 +Diluted +$ +0.38 +$ +0.28 +$ +0.51 +$ +0.11 +F-32 +Table of Contents +PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +Charged to +Costs and +Expenses +Deductions(1) +Ending +Balance +(In thousands) +Year Ended December 31, 2013 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +3,513 +$ +0 +$ +161 +$ +3,674 +Year Ended December 31, 2012 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +4,887 +$ +1,100 +$ +(2,474 +) +$ +3,513 +Year Ended December 31, 2011 +Deducted from asset accounts: +Allowance for doubtful accounts +$ +5,114 +$ +0 +$ +(227 +) +$ +4,887 +(1) +Consists of uncollectible accounts (written off) or recovered. +S-1 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form 10-K to be signed on its behalf by the +undersigned, thereunto duly authorized. +PATTERSON-UTI ENERGY, INC. +By: +/s/ William Andrew Hendricks, +Jr. +William Andrew Hendricks, Jr. +President and Chief Executive Officer +Date: February 14, 2014 +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 February 14, 2014. +Signature +Title +/s/ Mark S. +Siegel +Chairman of the Board +Mark S. Siegel +/s/ William Andrew Hendricks, +Jr. +President and Chief Executive Officer +William Andrew Hendricks, Jr. +(Principal Executive Officer) +/s/ John E. Vollmer +III +Senior Vice President — Corporate Development, +John E. Vollmer III +Chief Financial Officer and Treasurer +(Principal Financial and Accounting Officer) +/s/ Kenneth N. +Berns +Senior Vice President and Director +Kenneth N. Berns +/s/ Charles O. +Buckner +Director +Charles O. Buckner +/s/ Michael W. +Conlon +Director +Michael W. Conlon +/s/ Curtis W. +Huff +Director +Curtis W. Huff +/s/ Terry H. +Hunt +Director +Terry H. Hunt +/s/ Cloyce A. +Talbott +Director +Cloyce A. Talbott +Table of Contents +EXHIBIT INDEX +2.1 +Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure +Pumping Services, LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +2.2 +Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +2.3 +Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy +Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by +reference). +3.1 +Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, +2004 and incorporated herein by reference). +3.2 +Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period +ended June 30, 2004 and incorporated herein by reference). +3.3 +Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +3.4 +Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and +incorporated herein by reference). +10.1 +Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the +Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). +10.2 +Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the +quarterly period ended June 30, 2003 and incorporated herein by reference).* +10.3 +Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form +10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).* +10.4 +Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, +Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by +reference).* +10.5 +First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated +herein by reference). +10.6 +Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference). +Table of Contents +10.7 +Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.8 +Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and +incorporated herein by reference).* +10.9 +Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q and +incorporated herein by reference).* +10.10 +Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time (filed February 19, 2010 +as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference).* +10.11 +Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).* +10.12 +Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s +Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).* +10.13 +Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John +E. Vollmer III (filed 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).* +10.14 +Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form +10-K, as amended, and incorporated herein by reference).* +10.15 +Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Management Services, LLC and Douglas J. Wall (filed September 24, 2012 as Exhibit 10.1 to the +Company’s Current Report on Form 8-K, and incorporated herein by reference).* +10.16 +Employment Agreement, effective as of January 1, 2012, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb (filed February 10, 2012 as Exhibit 10.17 to the +Company’s Annual Report on Form 10-K for the year ended December 31, 2011 and incorporated herein by reference).* +10.17 +Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry +H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler, William Andrew Hendricks, Jr. and Michael W. Conlon (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year +ended December 31, 2003 and incorporated herein by reference).* +10.18 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as +Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +Table of Contents +10.19 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 +as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.20 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, +2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* +10.21 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.22 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.23 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to +the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.24 +First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit +10.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* +10.25 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as +Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* +10.26 +Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed July 30, +2012 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* +10.27 +Form of Offer Letter to William Andrew Hendricks, Jr. dated March 14, 2012 (filed March 16, 2012 as Exhibit 99.3 to the Company’s Current Report on Form 8-K and incorporated +herein by reference).* +10.28 +Severance Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William A. Hendricks, Jr. (filed July 30, 2012 as Exhibit 10.2 to the +Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* +10.29 +Credit Agreement dated September 27, 2012, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender +and lender and each of the other letter of credit issuer and lender parties thereto (filed September 28, 2012 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). +10.30 +Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +10.31 +Note Purchase Agreement dated June 14, 2012 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed June 18, 2012 as Exhibit 10.1 to the Company’s +Current Report on Form 8-K and incorporated herein by reference). +Table of Contents +21.1 +Subsidiaries of the Registrant.+ +23.1 +Consent of Independent Registered Public Accounting Firm.+ +31.1 +Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +31.2 +Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.+ +32.1 +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of +2002.+ +101 +The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting +Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Stockholders’ Equity, (v) the Consolidated +Statements of Cash Flows, and (vi) Notes to Consolidated Financial Statements.+ +* +Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. ++ +Filed herewith. \ No newline at end of file diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/filing_metadata.csv b/raw/filings/0000889900/2013/0001193125-14-054910/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..eebc9d4b781429e21c7a83dfa1c157c801037584 --- /dev/null +++ b/raw/filings/0000889900/2013/0001193125-14-054910/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000889900,PTEN,PATTERSON UTI ENERGY INC,10-K,2014-02-14,2013-12-31,2014-02-14T21:33:11.000Z,0001193125-14-054910,d639374d10k.htm,10-K,11184089,1,0,https://www.sec.gov/Archives/edgar/data/889900/000119312514054910/d639374d10k.htm,https://www.sec.gov/Archives/edgar/data/889900/000119312514054910/,2013,2013,1 diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/item1.txt b/raw/filings/0000889900/2013/0001193125-14-054910/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..0f67dc2226aa46b9f13f1cab201090dbff96cee2 --- /dev/null +++ b/raw/filings/0000889900/2013/0001193125-14-054910/item1.txt @@ -0,0 +1,1943 @@ +Item 1 of this Report and the information set forth in Note 3 of the Notes to Consolidated Financial Statements included in Item 8 of this Report. +Item 3. +Legal Proceedings. +In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the +Company tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and +retaliation. The Company and the EEOC are engaged in the statutory conciliation process. If such conciliation process is unsuccessful, the Company believes that litigation will ensue. The Company intends to defend itself vigorously and, +based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no +assurance as to the ultimate outcome of this matter. +Other than the matter described above, we are party to various legal +proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial +condition. +Item 4. +Mine Safety Disclosure. +Not applicable. +20 +Table of Contents +PART II +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +(a) +Market Information +Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol +“PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated: +High +Low +2012: +First quarter +$ +22.14 +$ +16.83 +Second quarter +17.70 +12.81 +Third quarter +17.75 +13.40 +Fourth quarter +19.21 +14.95 +2013: +First quarter +$ +25.48 +$ +18.59 +Second quarter +25.12 +18.96 +Third quarter +22.41 +18.83 +Fourth quarter +26.09 +21.29 +(b) +Holders +As of +February 7, 2014, there were approximately 1,100 holders of record of our common stock. +(c) +Dividends +We paid +cash dividends during the years ended December 31, 2012 and 2013 as follows: +Per Share +Total +(in thousands) +2012: +Paid on March 30, 2012 +$ +0.05 +$ +7,788 +Paid on June 29, 2012 +0.05 +7,650 +Paid on September 28, 2012 +0.05 +7,518 +Paid on December 28, 2012 +0.05 +7,346 +Total cash dividends +$ +0.20 +$ +30,302 +2013: +Paid on March 29, 2013 +$ +0.05 +$ +7,312 +Paid on June 28, 2013 +0.05 +7,361 +Paid on September 30, 2013 +0.05 +7,231 +Paid on December 31, 2013 +0.05 +7,208 +Total cash dividends +$ +0.20 +$ +29,112 +On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the +amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon +business conditions, results of operations, financial condition, terms of our credit facilities and other factors. +21 +Table of Contents +(e) +Issuer Purchases of Equity Securities +The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2013. +Period Covered +Total +Number of +Shares +Purchased +Average Price +Paid +per +Share +Total Number +of +Shares (or Units) +Purchased as Part +of Publicly +Announced Plans +or Programs +Approximate Dollar +Value of +Shares +That May Yet Be +Purchased Under the +Plans or +Programs (in +thousands)(1) +October 2013(2) +4,459 +$ +23.15 +896 +$ +187,483 +November 2013 +— +$ +— +— +$ +187,483 +December 2013 +— +$ +— +— +$ +187,483 +Total +4,459 +$ +23.15 +896 +$ +187,483 +(1) +On September 6, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in +open market or privately negotiated transactions. +(2) +We withheld 3,563 shares in October 2013 with respect to employees’ tax withholding obligations upon the vesting of restricted shares. The price used to determine +the number of shares withheld was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and +not pursuant to the stock buyback program. +22 +Table of Contents +(e) +Performance Graph +The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2008 through +December 31, 2013, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of +Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Energy Services Corp. and Precision Drilling Corp. All of the companies in our peer group are providers of land-based drilling services. Nabors Industries, Ltd. also is a provider of +pressure pumping services. The graph assumes investment of $100 on December 31, 2008 and reinvestment of all dividends. +Fiscal Year Ended December 31, +Company/Index +2008 +($) +2009 +($) +2010 +($) +2011 +($) +2012 +($) +2013 +($) +Patterson-UTI Energy, Inc. +100.00 +135.50 +192.50 +179.97 +169.86 +232.96 +Peer Group Index +100.00 +161.96 +188.47 +182.58 +161.04 +215.29 +S&P 500 Stock Index +100.00 +126.46 +145.51 +148.59 +172.37 +228.19 +Oilfield Service Index +100.00 +162.11 +205.75 +184.05 +189.89 +246.06 +S&P MidCap Index +100.00 +137.38 +173.98 +170.96 +201.53 +269.04 +The foregoing graph is based on historical data and is not necessarily indicative of future performance. +This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act. +23 +Table of Contents +Item 6. +Selected Financial Data. +Our selected consolidated financial data as of December 31, 2013, 2012, 2011, 2010 and 2009, and for each of the five years in the period ended December 31, 2013 should be read in conjunction +with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Due to the sale +of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January 2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations for all +periods presented. +Years Ended December 31, +2013 +2012 +2011 +2010 +2009 +(In thousands, except per share amounts) +Statement of Operations Data: +Operating revenues: +Contract drilling +$ +1,679,611 +$ +1,821,713 +$ +1,669,581 +$ +1,081,898 +$ +599,287 +Pressure pumping +979,166 +841,771 +845,803 +350,608 +161,441 +Oil and natural gas +57,257 +59,930 +50,559 +30,425 +21,218 +Total +2,716,034 +2,723,414 +2,565,943 +1,462,931 +781,946 +Operating costs and expenses: +Contract drilling +968,754 +1,075,491 +972,778 +655,678 +357,742 +Pressure pumping +744,243 +580,878 +561,398 +235,100 +124,100 +Oil and natural gas +12,909 +11,303 +9,615 +7,020 +7,341 +Depreciation, depletion, amortization and impairment +597,469 +526,614 +437,279 +333,493 +289,847 +Selling, general and administrative +73,852 +64,473 +64,271 +53,042 +43,935 +Net (gain) loss on asset disposals +(3,384 +) +(33,806 +) +(4,999 +) +(22,812 +) +3,385 +Provision for bad debts +— +1,100 +— +(2,000 +) +3,810 +Acquisition-related expenses +— +— +— +2,485 +— +Total +2,393,843 +2,226,053 +2,040,342 +1,262,006 +830,160 +Operating income (loss) +322,191 +497,361 +525,601 +200,925 +(48,214 +) +Other expense +(25,750 +) +(21,688 +) +(14,883 +) +(10,171 +) +(3,341 +) +Income (loss) from continuing operations before income taxes +296,441 +475,673 +510,718 +190,754 +(51,555 +) +Income tax expense (benefit) +108,432 +176,196 +187,938 +72,856 +(17,595 +) +Income (loss) from continuing operations +$ +188,009 +$ +299,477 +$ +322,780 +$ +117,898 +$ +(33,960 +) +Income (loss) from continuing operations per common share: +Basic +$ +1.29 +$ +1.96 +$ +2.08 +$ +0.77 +$ +(0.22 +) +Diluted +$ +1.28 +$ +1.96 +$ +2.06 +$ +0.76 +$ +(0.22 +) +Cash dividends per common share +$ +0.20 +$ +0.20 +$ +0.20 +$ +0.20 +$ +0.20 +Weighted average number of common shares outstanding: +Basic +144,356 +151,144 +153,871 +152,772 +152,069 +Diluted +145,303 +151,699 +155,304 +153,276 +152,069 +Balance Sheet Data: +Total assets +$ +4,687,127 +$ +4,556,911 +$ +4,221,901 +$ +3,423,031 +$ +2,662,152 +Borrowings under line of credit +— +— +110,000 +— +— +Other long term debt +682,500 +692,500 +382,500 +392,500 +— +Stockholders’ equity +2,755,997 +2,640,657 +2,516,631 +2,187,607 +2,081,700 +Working capital +454,373 +340,128 +346,238 +241,445 +263,511 +24 +Table of Contents +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +Management Overview — We are a leading provider of 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 pressure pumping services. In addition to these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties. +We acquired an electric wireline business on October 1, 2010 and sold the business on January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this +Report. +As of December 31, 2013, we had a drilling fleet that consisted of 279 marketable land-based drilling rigs. There +continues to be uncertainty with respect to the global economic environment, crude oil and natural gas prices are volatile and natural gas prices have been low in recent years. Activity in our drilling business decreased in the fourth quarter of +2013 compared to the fourth quarter of 2012. In the fourth quarter of 2013, our average number of rigs operating decreased to 192, as compared to an average of 206 drilling rigs operating during the same period in 2012. +We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource +plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of December 31, 2013, we have completed 124 new APEX ® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 20 additional new APEX ® rigs in 2014. In connection with horizontal shale and other unconventional resource plays, we have added equipment +to perform service intensive fracturing jobs. As of December 31, 2013, we had approximately 763,000 hydraulic horsepower in our pressure pumping fleet. This is a net increase of approximately 610,000 horsepower since the end of 2009. Low +natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America. +We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term +of six months or more. Our backlog as of December 31, 2013 was approximately $946 million. We expect approximately $660 million of our backlog to be realized in 2014. We generally calculate our backlog by multiplying the day rate under our term +drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions +in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are +subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts for which we have received an early termination notice, our backlog +calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate. See Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Not Ultimately Be Realized as +Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment. +For the three years ended +December 31, 2013, our operating revenues from continuing operations consisted of the following (dollars in thousands): +2013 +2012 +2011 +Contract drilling +$ +1,679,611 +62 +% +$ +1,821,713 +67 +% +$ +1,669,581 +65 +% +Pressure pumping +979,166 +36 +841,771 +31 +845,803 +33 +Oil and natural gas +57,257 +2 +59,930 +2 +50,559 +2 +$ +2,716,034 +100 +% +$ +2,723,414 +100 +% +$ +2,565,943 +100 +% +Generally, the profitability of our business is impacted most by two primary factors in our contract +drilling segment: our average number of rigs operating and our average revenue per operating day. During 2013, our average number of rigs operating was 184 in the United States and 8 in Canada compared to 214 in the United States and 7 in +Canada in 2012 and 205 in the United States and 11 in Canada in 2011. Our average +25 +Table of Contents +revenue per operating day was $24,020 in 2013 compared to $22,540 in 2012 and $21,200 in 2011. We had consolidated net income of $188 million for 2013 compared to $299 million for 2012. The +decrease in consolidated net income was primarily due to lower revenue as a result of fewer rigs operating, lower profitability on pressure pumping revenues, higher depreciation expense and a gain on assets disposals in 2012 with no similar gain in +2013. Depreciation, depletion, amortization and impairment expense for 2013 includes a charge of $7.9 million related to removing 48 rigs from our marketable fleet. It also includes a charge of $29.9 million related to 55 mechanical rigs that +were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs. +Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural +gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing +for our services. Natural gas prices and our monthly average number of rigs operating have declined from recent highs. In December 2013, our average number of rigs operating was 187 in the United States and 9 in Canada. +We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues and various other +factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report. +Critical Accounting Policies +In addition to established accounting +policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue +recognition, the use of estimates and oil and natural gas properties. +Property and equipment — Property and +equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line +method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining +depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances (“triggering events”) indicate that the carrying values of certain +assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of +our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s +expectations of future trends, we estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as +management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book +value. Any provision for impairment is measured at fair value. +On a periodic basis, we evaluate our fleet of drilling rigs for +marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling +longer horizontal wells using high capacity rigs). In connection with our ongoing planning process, we evaluated our then-current fleet of marketable drilling rigs in 2013, 2012 and 2011 and identified 48, 36 and 53 rigs, during each of those years, +respectively, that we determined would no longer be marketed as rigs based on our assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as well as our assessment of future demand and the +suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs +26 +Table of Contents +were transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs were retired. The net book values of these assets of $7.9 million in 2013, +$5.2 million in 2012 and $15.7 million in 2011 were expensed in our consolidated statements of operations. +In 2013, due +to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded in our consolidated statement of operations a charge of $29.9 million related to 55 mechanical rigs that were not under +contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. +We also evaluate our fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure +pumping equipment that would be retired. The net book value of these assets of $7.3 million was expensed in our consolidated statements of operations. There were no similar charges in 2013 or 2011. +In light of the levels of activity and revenue per operating day experienced by us and our peers in 2013, 2012 and 2011, we concluded that +no triggering events occurred during these years with respect to our contract drilling segment as a whole which would indicate that the carrying amounts of long-lived assets in that segment may not be recoverable. We also concluded that no +triggering event occurred with respect to our pressure pumping segment in 2013, 2012 or 2011. Impairment considerations related to our oil and natural gas segment are discussed below. +Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. We evaluate goodwill at +least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our +reporting units for impairment testing have been determined to be the same as our operating segments. We currently have goodwill in our contract drilling and pressure pumping operating segments. We first determine whether it is more likely than not +that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, we may perform the +first step of quantitative testing for goodwill impairment in lieu of performing a qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If +the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any +remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall. +In connection with our annual goodwill impairment assessment as of December 31, 2012, we determined based on an assessment of +qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, we considered the continued demand +experienced during 2012 for our services in the contract drilling and pressure pumping businesses. We also considered the then current and expected levels of commodity prices for crude oil and natural gas, which influence the overall level of +business activity in these operating segments. Additionally, operating results for 2012 and forecasted operating results for 2013 were also taken into account. Our overall market capitalization and the large amount of calculated excess of the fair +values of our reporting units over their carrying values and lack of significant changes in the key assumptions from our 2010 quantitative Step 1 assessment of goodwill were also considered. +We performed a quantitative impairment assessment of our goodwill as of December 31, 2013. In completing the first step of the +analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting units. In developing this fair value estimate, we applied key +assumptions including an assumed discount rate of 11.87% for the contract drilling reporting unit and an assumed discount rate of 12.40% for the pressure pumping reporting unit. An assumed long-term growth rate of 3.00% was used for both reporting +units. Based on the +27 +Table of Contents +results of the first step of the impairment test in 2013, we concluded that no impairment was indicated in our contract drilling or pressure pumping reporting units as the estimated fair value of +each reporting unit exceeded its carrying value. +We have undertaken extensive efforts in the past several years to upgrade our +fleet of equipment and believe that we are well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional +vertical wells that has resulted primarily from low natural gas prices. In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, +and such impairment could be material. +Revenue recognition — Revenues from daywork drilling and pressure pumping +activities are recognized as services are performed. Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells we drilled in 2013, 2012 and 2011 were drilled under +daywork contracts. +Use of estimates — The preparation of financial statements in conformity with accounting +principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and +liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. +Key estimates used by management include: +• +allowance for doubtful accounts, +• +depreciation, depletion and amortization, +• +fair values of assets acquired and liabilities assumed in acquisitions, +• +goodwill and long-lived asset impairments, and +• +reserves for self-insured levels of insurance coverage. +Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of +accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are +charged to expense when such determination is made. 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 whether sufficient progress +is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider +the well costs 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 and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total +proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil +and natural gas reserves for each respective field. +We review our proved oil and natural gas properties for impairment +whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our +expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is +measured and recognized as the difference between net book value and fair value. The fair +28 +Table of Contents +value estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field and the net future cash inflows from developing and +operating these fields. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and +abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $4.0 million, $1.9 +million and $3.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion, amortization and impairment in the consolidated statements of operations. +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. +Liquidity and Capital Resources +As of December 31, 2013, we had working capital of $454 million, including cash and cash equivalents of $250 million, compared to working capital of $340 million and cash and cash equivalents of $111 +million at December 31, 2012. +During 2013, our sources of cash flow included: +• +$889 million from operating activities, +• +$11.8 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and +• +$10.4 million in proceeds from the disposal of property and equipment. +During 2013, we used $73.5 million to repurchase shares of our common stock, $29.1 million to pay dividends on our common stock, $6.3 +million to repay long-term debt and $662 million: +• +to build new drilling rigs and pressure pumping equipment, +• +to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment, +• +to acquire and procure equipment and facilities for our drilling and pressure pumping operations, and +• +to fund investments in oil and natural gas properties on a working interest basis. +We paid cash dividends during the year ended December 31, 2013 as follows: +Per Share +Total +(in thousands) +Paid on March 29, 2013 +$ +0.05 +$ +7,312 +Paid on June 28, 2013 +0.05 +7,361 +Paid on September 30, 2013 +0.05 +7,231 +Paid on December 31, 2013 +0.05 +7,208 +Total cash dividends +$ +0.20 +$ +29,112 +On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of +$0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business +conditions, results of operations, financial condition, terms of our credit facilities and other factors. +On August 1, +2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. On July 25, 2012, our Board of Directors terminated the remaining +authority under the 2007 stock buyback program, and approved a +29 +Table of Contents +new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions. On September 6, 2013, the Company’s Board +of Directors terminated any remaining authority under the 2012 stock buyback program, and approved a new stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated +transactions. As of December 31, 2013, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as +treasury stock. +We acquired shares of stock from employees during 2013, 2012 and 2011 that are accounted for as treasury +stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options by employees. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of +stock options, the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term +Incentive Plan (the “2005 Plan”) and not pursuant to the stock buyback program. +Treasury stock acquisitions during +the year ended December 31, 2013, 2012 and 2011 were as follows (dollars in thousands): +2013 +2012 +2011 +Shares +Cost +Shares +Cost +Shares +Cost +Treasury shares at beginning of period +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +27,343,814 +$ +620,445 +Purchases pursuant to stock buyback programs: +2007 program +— +— +4,708,784 +70,092 +8,689 +255 +2012 program +2,567,266 +51,107 +5,863,451 +98,892 +— +— +2013 program +602,564 +12,517 +— +— +— +— +Acquisitions Pursuant to the 2005 Long-Term Incentive Plan +951,489 +22,213 +86,932 +1,308 +135,068 +4,059 +Treasury shares at end of period +42,268,057 +$ +880,888 +38,146,738 +$ +795,051 +27,487,571 +$ +624,759 +On September 27, 2012, we entered into a credit agreement (the “Credit Agreement”). The +Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced a previous senior unsecured revolving credit facility. +The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility +contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time. +The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments which commenced +December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% +of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments. +Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, +not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility. +Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The +applicable margin on LIBOR +30 +Table of Contents +rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of +December 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the amount +available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%. +The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization +ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must +not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and +amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2013. The Credit Agreement also contains customary representations, +warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. +Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial +and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have +the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to +insolvency and bankruptcy such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit. +As of December 31, 2013, we had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. We +had $39.8 million in letters of credit outstanding at December 31, 2013 and, as a result, had available borrowing capacity of approximately $460 million at that date. +On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a +private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020. +On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior +Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We will pay interest on the Series B Notes on April 5 and October 5 of each year. The +Series B Notes will mature on June 14, 2022. +The Series A Notes and Series B Notes are prepayable at our option, in whole +or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount +prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we +must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the +principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date. +The respective note purchase +agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total +borrowed money indebtedness to (b) the sum of such +31 +Table of Contents +indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio +as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior quarters to interest charges for the same period. We were in +compliance with these covenants at December 31, 2013. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. +Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the +financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other +insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately +due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable. +We believe that our liquidity as of December 31, 2013, which includes approximately $454 million in working capital and +approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make +improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from +operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all. +Commitments and Contingencies — As of December 31, 2013, we maintained letters of credit in the aggregate amount of $39.8 +million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various +times during the year and are typically renewed. As of December 31, 2013, no amounts had been drawn under the letters of credit. +As of December 31, 2013, we had commitments to purchase approximately $225 million of major equipment for our drilling and pressure pumping businesses. +Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. +These agreements expire in 2016 and 2017. As of December 31, 2013, the remaining obligation under these agreements was approximately $25.2 million, of which materials with a total purchase price of approximately $7.7 million are expected to be +delivered during 2014. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. +In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such +vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to +purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2013, advances of approximately $11.8 million had been made under this agreement and repayments of approximately +$2.6 million had been received resulting in a balance outstanding of approximately $9.2 million. +In May 2013, the U.S. Equal +Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and +race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC are engaged in the statutory conciliation process. If such +conciliation process is unsuccessful, we believe that litigation will ensue. We intend to defend ourself vigorously and, based on the information available +32 +Table of Contents +to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no +assurance as to the ultimate outcome of this matter. +Trading and Investing — We have not engaged in trading +activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts. +Contractual Obligations +The following table presents information with respect to our contractual obligations as of December 31, 2013 (dollars in thousands): +Payments due by period +Total +Less than +1 year +1-3 years +3-5 years +More than 5 +years +Term loan(1) +$ +92,500 +$ +10,000 +$ +41,250 +$ +41,250 +— +Interest on term loan(2) +6,329 +2,247 +3,572 +510 +— +Series A Notes(3) +300,000 +— +— +— +300,000 +Interest on Series A Notes(4) +100,850 +14,910 +29,820 +29,820 +26,300 +Series B Notes(5) +300,000 +— +— +— +300,000 +Interest on Series B Notes(6) +108,316 +12,810 +25,620 +25,620 +44,266 +Equipment purchases(7) +225,354 +225,354 +— +— +— +Inventory purchases(8) +25,198 +7,735 +15,438 +2,025 +— +$ +1,158,547 +$ +273,056 +$ +115,700 +$ +99,225 +$ +670,566 +(1) +Represents repayments of borrowings under the term loan portion of the Credit Agreement. The term loan matures on September 27, 2017. +(2) +Interest to be paid on term loan using 2.50% rate in effect as of December 31, 2013. +(3) +Principal repayment of the Series A Notes is required at maturity on October 5, 2020. +(4) +Interest to be paid on the Series A Notes using 4.97% coupon rate. +(5) +Principal repayment of the Series B Notes is required at maturity on June 14, 2022 +(6) +Interest to be paid on the Series B Notes using 4.27% coupon rate. +(7) +Represents commitments to purchase major equipment to be delivered in 2014 based on expected delivery dates. +(8) +Represents commitments to purchase proppants and chemicals for our pressure pumping business. +33 +Table of Contents +Off-Balance Sheet Arrangements +We had no off-balance sheet arrangements at December 31, 2013. +Results of Operations +Comparison of the years ended +December 31, 2013 and 2012 +The following tables summarize operations by business segment for the years ended +December 31, 2013 and 2012: +Year Ended December 31, +Contract Drilling +2013 +2012 +% Change +(Dollars in thousands) +Revenues +$ +1,679,611 +$ +1,821,713 +(7.8 +)% +Direct operating costs +968,754 +1,075,491 +(9.9 +)% +Margin(1) +710,857 +746,222 +(4.7 +)% +Selling, general and administrative +5,867 +6,513 +(9.9 +)% +Depreciation, amortization and impairment +438,728 +390,316 +12.4 +% +Operating income +$ +266,262 +$ +349,393 +(23.8 +)% +Operating days +69,918 +80,833 +(13.5 +)% +Average revenue per operating day +$ +24.02 +$ +22.54 +6.6 +% +Average direct operating costs per operating day +$ +13.86 +$ +13.31 +4.1 +% +Average margin per operating day(1) +$ +10.17 +$ +9.23 +10.2 +% +Average rigs operating +192 +221 +(13.1 +)% +Capital expenditures +$ +504,508 +$ +744,949 +(32.3 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per operating day is defined as margin divided by operating days. +The demand for our contract +drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has contributed to an excess capacity of land drilling rigs compared to +demand. Recently, customer demand has shifted away from mechanically powered drilling rigs to electric powered drilling rigs, reducing the utilization rates of our mechanically powered drilling rigs. The average market price of natural gas and oil +for each of the fiscal quarters and full year in 2013 and 2012 follows: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2012: +Average natural gas price per +Mcf(1) +$ +2.45 +$ +2.28 +$ +2.88 +$ +3.40 +$ +2.75 +Average oil price per Bbl(2) +$ +102.88 +$ +93.42 +$ +92.24 +$ +87.96 +$ +94.12 +2013: +Average natural gas price per +Mcf(1) +$ +3.49 +$ +4.01 +$ +3.55 +$ +3.85 +$ +3.73 +Average oil price per Bbl(2) +$ +94.34 +$ +94.10 +$ +105.84 +$ +97.34 +$ +97.91 +(1) +The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +34 +Table of Contents +Revenues and direct operating costs decreased in 2013 compared to 2012 +as a result of a decrease in the number of rigs operating. A greater proportion of our high specification APEX ® +rigs working combined with early contract termination revenues caused an increase in the average revenue per operating day. Capital expenditures were incurred in 2013 and 2012 to build new drilling rigs, to modify and upgrade existing drilling rigs +and to acquire additional equipment including top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately +$7.9 million in 2013 and approximately $5.2 million in 2012 of charges related to drilling equipment on drilling rigs that were retired from our marketable fleet. We retired 48 rigs from our marketable fleet in 2013 and retired 36 rigs from our +marketable fleet in 2012. In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded additional depreciation, amortization and impairment expense of $29.9 million +related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no +similar charges in 2012 or 2011. Significant capital expenditures incurred in recent years to add new rig capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Pressure Pumping +2013 +2012 +% Change +(Dollars in thousands) +Revenues +$ +979,166 +$ +841,771 +16.3 +% +Direct operating costs +744,243 +580,878 +28.1 +% +Margin(1) +234,923 +260,893 +(10.0 +)% +Selling, general and administrative +17,695 +17,036 +3.9 +% +Depreciation, amortization and impairment +129,984 +111,062 +17.0 +% +Operating income +$ +87,244 +$ +132,795 +(34.3 +)% +Fracturing jobs +1,261 +1,229 +2.6 +% +Other jobs +4,800 +5,659 +(15.2 +)% +Total jobs +6,061 +6,888 +(12.0 +)% +Average revenue per fracturing job +$ +705.57 +$ +590.70 +19.4 +% +Average revenue per other job +$ +18.63 +$ +20.46 +(8.9 +)% +Average revenue per total job +$ +161.55 +$ +122.21 +32.2 +% +Average direct operating costs per total job +$ +122.79 +$ +84.33 +45.6 +% +Average margin per total job(1) +$ +38.76 +$ +37.88 +2.3 +% +Margin as a percentage of total revenues(1) +24.0 +% +31.0 +% +(22.6 +)% +Capital expenditures +$ +122,782 +$ +194,117 +(36.7 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. +In connection with the development of unconventional reservoirs, customers have continued to increase the average size of the fracturing jobs. As a result, we have experienced an increase in the size of +these multi-stage fracturing jobs resulting in higher revenues and costs. Average revenue per fracturing job increased as a result of this increase in the larger multi-stage fracturing jobs in 2013 as compared to 2012. Average direct operating costs +per total job increased primarily as a result of increased amounts of materials and labor used on the larger multi-stage fracturing jobs. Depreciation, amortization and impairment expense increased in 2013 due primarily to significant capital +expenditures incurred in recent years to add capacity. In 2012, depreciation, amortization and +35 +Table of Contents +impairment expenses included approximately $7.3 million related to the retirement of certain pressure pumping equipment. There were no comparable charges in 2013. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2013 +2012 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +51,583 +$ +55,335 +(6.8 +)% +Revenues — Natural gas and liquids +5,674 +4,595 +23.5 +% +Revenues — Total +57,257 +59,930 +(4.5 +)% +Direct operating costs +12,909 +11,303 +14.2 +% +Margin(1) +44,348 +48,627 +(8.8 +)% +Depletion and impairment +24,400 +21,417 +13.9 +% +Operating income +$ +19,948 +$ +27,210 +(26.7 +)% +Capital expenditures +$ +31,245 +$ +29,888 +4.5 +% +(1) +Margin is defined as revenues less direct operating costs and excludes depletion and impairment. +Oil revenues decreased as a result of lower production partially offset by higher average oil prices. Natural gas and liquids revenue +increased due to higher average prices and higher production. Direct operating costs and depletion expense also increased primarily due to the addition of new wells. Depletion and impairment expense in 2013 includes approximately $4.0 million of oil +and natural gas property impairments compared to approximately $1.9 million of oil and natural gas property impairments in 2012. +Year Ended December 31, +Corporate and Other +2013 +2012 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +50,290 +$ +40,924 +22.9 +% +Depreciation +$ +4,357 +$ +3,819 +14.1 +% +Net gain on asset disposals +$ +(3,384 +) +$ +(33,806 +) +(90.0 +)% +Provision for bad debts +$ +— +$ +1,100 +(100.0 +)% +Interest income +$ +918 +$ +554 +65.7 +% +Interest expense +$ +28,359 +$ +22,750 +24.7 +% +Other income +$ +1,691 +$ +508 +232.9 +% +Capital expenditures +$ +3,926 +$ +5,034 +(22.0 +)% +Selling, general and administrative expense for 2013 increased primarily due to higher costs associated +with stock-based compensation and expenses to evaluate and prepare for international growth opportunities. Selling, general and administrative expense in 2012 included a reduction in personnel costs related to the final determination of payouts +under the 2009 Performance Unit Awards upon the completion of the performance period. There was no similar reduction in 2013. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate +to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction +sale of certain excess drilling assets. An additional provision for bad debts was recorded in 2012 with no similar increase in 2013. Interest expense increased in 2013 primarily due to a full year of interest charges related to the $300 million +of Series B Senior Notes issued and sold on June 14, 2012. +36 +Table of Contents +Comparison of the years ended December 31, 2012 and 2011 +The following tables summarize operations by business segment for the years ended December 31, 2012 and 2011: +Year Ended December 31, +Contract Drilling +2012 +2011 +% Change +(Dollars in thousands) +Revenues +$ +1,821,713 +$ +1,669,581 +9.1 +% +Direct operating costs +1,075,491 +972,778 +10.6 +% +Margin(1) +746,222 +696,803 +7.1 +% +Selling, general and administrative +6,513 +6,408 +1.6 +% +Depreciation, amortization and impairment +390,316 +344,312 +13.4 +% +Operating income +$ +349,393 +$ +346,083 +1.0 +% +Operating days +80,833 +78,758 +2.6 +% +Average revenue per operating day +$ +22.54 +$ +21.20 +6.3 +% +Average direct operating costs per operating day +$ +13.31 +$ +12.35 +7.8 +% +Average margin per operating day(1) +$ +9.23 +$ +8.85 +4.3 +% +Average rigs operating +221 +216 +2.3 +% +Capital expenditures +$ +744,949 +$ +784,686 +(5.1 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per operating day is defined as margin divided by operating days. +The demand for our contract +drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States contributed to an excess capacity of land drilling rigs compared to demand. The average market +price of natural gas and oil for each of the fiscal quarters and full year in 2012 and 2011 follows: +1st Quarter +2nd Quarter +3rd Quarter +4th Quarter +Year +2011: +Average natural gas price per +Mcf(1) +$ +4.18 +$ +4.37 +$ +4.12 +$ +3.32 +$ +4.00 +Average oil price per Bbl(2) +$ +93.50 +$ +102.22 +$ +89.72 +$ +93.99 +$ +94.86 +2012: +Average natural gas price per +Mcf(1) +$ +2.45 +$ +2.28 +$ +2.88 +$ +3.40 +$ +2.75 +Average oil price per Bbl(2) +$ +102.88 +$ +93.42 +$ +92.24 +$ +87.96 +$ +94.12 +(1) +The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. +(2) +The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. +Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of +operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual day rates. Average direct operating costs per operating day +increased in 2012 due primarily to higher labor-related and rig mobilization costs. The increase in operating days was largely due to increased demand during the first six months of 2012 resulting from higher oil prices and the addition of newbuild +APEX ® rigs into our drilling fleet. Capital +37 +Table of Contents +expenditures were incurred in 2012 and 2011 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional equipment including top drives, drill pipe, drill +collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately $5.2 million in 2012 and approximately $15.7 million in 2011 of charges +related to drilling equipment and drilling rigs that were retired from our marketable fleet. We retired 36 rigs from our marketable fleet in 2012 and retired 53 rigs from our marketable fleet in 2011. Significant capital expenditures incurred in +recent years to add new rig capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Pressure Pumping +2012 +2011 +% Change +(Dollars in thousands) +Revenues +$ +841,771 +$ +845,803 +(0.5 +)% +Direct operating costs +580,878 +561,398 +3.5 +% +Margin(1) +260,893 +284,405 +(8.3 +)% +Selling, general and administrative +17,036 +17,686 +(3.7 +)% +Depreciation, amortization and impairment +111,062 +73,279 +51.6 +% +Operating income +$ +132,795 +$ +193,440 +(31.4 +)% +Fracturing jobs +1,229 +1,531 +(19.7 +)% +Other jobs +5,659 +7,010 +(19.3 +)% +Total jobs +6,888 +8,541 +(19.4 +)% +Average revenue per fracturing job +$ +590.70 +$ +467.85 +26.3 +% +Average revenue per other job +$ +20.46 +$ +18.48 +10.7 +% +Average revenue per total job +$ +122.21 +$ +99.03 +23.4 +% +Average direct operating costs per total job +$ +84.33 +$ +65.73 +28.3 +% +Average margin per total job(1) +$ +37.88 +$ +33.30 +13.8 +% +Margin as a percentage of revenues(1) +31.0 +% +33.6 +% +(7.7 +)% +Capital expenditures +$ +194,117 +$ +198,061 +(2.0 +)% +(1) +Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. +Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. +Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional +equipment to meet this demand and expand our area of operations. As a result, although the total number of fracturing jobs has decreased, we have experienced an increase in these larger multi-stage fracturing jobs as a proportion of the total +fracturing jobs we performed. Average revenue per fracturing job increased primarily as a result of this increase in the number of larger multi-stage fracturing jobs in 2012 as compared to 2011. Average revenue per other job increased as a result of +a change in job mix. The increase in the number of larger multi-stage fracturing jobs caused an increase in average direct operating costs per total job primarily increased costs of materials and higher labor-related costs. Depreciation, +amortization and impairment expense increased in 2012 due to a charge of approximately $7.3 million related to approximately 37,000 horsepower of pressure pumping equipment that was +38 +Table of Contents +retired. Significant capital expenditures incurred in recent years to add capacity also contributed to the increase in depreciation expense. +Year Ended December 31, +Oil and Natural Gas Production and Exploration +2012 +2011 +% Change +(Dollars in thousands, except +commodity prices) +Revenues — Oil +$ +55,335 +$ +44,495 +24.4 +% +Revenues — Natural gas and liquids +4,595 +6,064 +(24.2 +)% +Revenues — Total +59,930 +50,559 +18.5 +% +Direct operating costs +11,303 +9,615 +17.6 +% +Margin(1) +48,627 +40,944 +18.8 +% +Depletion and impairment +21,417 +16,962 +26.3 +% +Operating income +$ +27,210 +$ +23,982 +13.5 +% +Capital expenditures +$ +29,888 +$ +22,884 +30.6 +% +(1) +Margin is defined as revenues less direct operating costs and excludes depletion and impairment. +Oil revenues increased primarily as a result of increased production. Oil production increased primarily due to the addition of new wells. +Natural gas and liquids revenue decreased as a result of lower prices partially offset by increased production. Depletion and impairment expense in 2012 includes approximately $1.9 million of oil and natural gas property impairments compared to +approximately $3.0 million of oil and natural gas property impairments in 2011. Depletion expense increased approximately $5.6 million in 2012 compared to 2011 primarily due to increased production. +Year Ended December 31, +Corporate and Other +2012 +2011 +% Change +(Dollars in thousands) +Selling, general and administrative +$ +40,924 +$ +40,177 +1.9 +% +Depreciation +$ +3,819 +$ +2,726 +40.1 +% +Net gain on asset disposals +$ +(33,806 +) +$ +(4,999 +) +576.3 +% +Provision for bad debts +$ +1,100 +$ +— +N/M +Interest income +$ +554 +$ +187 +196.3 +% +Interest expense +$ +22,750 +$ +15,652 +45.3 +% +Other income +$ +508 +$ +582 +(12.7 +)% +Capital expenditures +$ +5,034 +$ +5,947 +15.4 +% +The increase in depreciation expense relates primarily to a new enterprise resource planning system. Gains +and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of +approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction sale of certain excess drilling assets. A provision for bad debts was recognized in 2012 with respect to accounts +receivable balances that are estimated to be uncollectible. Interest expense increased in 2012 due primarily to deferred debt issuance costs of $978,000 that were charged to expense as a result of the early termination of the prior credit facility +and to interest charges related to the $300 million of +39 +Table of Contents +Series B Senior Notes issued and sold on June 14, 2012. Capital expenditures decreased in 2012 due to less activity with respect to the implementation of the new enterprise resource planning +system. +Year Ended December 31, +Discontinued Operations: +2012 +2011 +% Change +(Dollars in thousands) +Electric wireline revenue +$ +— +$ +1,104 +(100 +)% +Electric wireline direct operating costs +$ +— +$ +1,831 +(100 +)% +Selling, general and administrative +$ +— +$ +46 +(100 +)% +Income tax benefit +$ +— +$ +(209 +) +(100 +)% +Loss from discontinued operations, net of income taxes +$ +— +$ +(367 +) +(100 +)% +On January 27, 2011, we sold our electric wireline business, which had been acquired by us on +October 1, 2010. The results of operations of this business have been classified as a discontinued operation. +Income Taxes +Year Ended December 31, +2013 +2012 +2011 +(Dollars in thousands) +Income from continuing operations before income tax +$ +296,441 +$ +475,673 +$ +510,718 +Income tax expense +$ +108,432 +$ +176,196 +$ +187,938 +Effective tax rate +36.6 +% +37.0 +% +36.8 +% +The effective tax rate is a result of a federal rate of 35.0% adjusted as follows: +2013 +2012 +2011 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income taxes +3.7 +2.5 +2.5 +Permanent differences +(1.5 +) +(0.2 +) +(0.1 +) +Other, net +(0.6 +) +(0.3 +) +(0.6 +) +Effective tax rate +36.6 +% +37.0 +% +36.8 +% +The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 +(as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent difference for 2011 does not include any +deduction as it is limited to taxable income and we had a tax loss in 2011. The permanent difference for 2012 does not include any deduction as it is limited to taxable income and we did not have taxable income in 2012 due to the utilization of net +operating loss carryforwards. The permanent difference for 2013 includes a deduction of $10.0 million as we fully utilized our remaining net operating loss carryforwards. +We record deferred federal income taxes based primarily on the temporary differences between the book and tax bases of our assets and liabilities. Deferred tax assets and liabilities are measured using +enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as +these benefits are utilized. We recognized deferred tax expense of approximately $51 million in 2013, $160 million in 2012 and $159 million in 2011. +On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are +lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the +Canadian assets. +40 +Table of Contents +As a result of the above conversion, our Canadian assets are no longer directly subject to +United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and intend to do so for the +foreseeable future. As a result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $38.5 million as of December 31, 2013. The unrecognized deferred tax +liability associated with these earnings was approximately $5.9 million, net of available foreign tax credits. This liability would be recognized if we received a dividend of the unremitted earnings. +Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition +Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about +future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as market supply and demand, domestic and international military, political, economic and weather conditions, the +ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and production and the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market +prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the +prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets +continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot +price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of +drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil +prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United +States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined from historic highs. +We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our +drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or +curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services. +Impact of Inflation +Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2013. We believe +that inflation will not have a significant near-term impact on our financial position. +Recently Issued Accounting Standards +In February 2013, the FASB issued an accounting standards update that requires additional disclosures regarding +reclassifications out of accumulated other comprehensive income. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012, and became effective for us in the quarter ended +March 31, 2013. The adoption of this update did not have a material impact on the disclosures included in our consolidated financial statements. We include in accumulated other comprehensive income the cumulative translation adjustment of our +foreign subsidiary. +41 +Table of Contents +In February 2013, the FASB issued an accounting standards update to provide guidance for the +recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations +addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount +the reporting entity expects to pay on behalf of its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are +effective during interim and annual periods beginning after December 15, 2013. The adoption of this update is not expected to have a material impact on our consolidated financial statements. +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +We currently have exposure to interest rate market risk associated with any borrowings that we have under our term credit facility or our +revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans +ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2013, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2013, we had no borrowings outstanding under +our revolving credit facility and $92.5 million outstanding under our term credit facility at an interest rate of 2.50%. The interest rate on the borrowing outstanding under our term credit facility is variable and adjusts at each interest payment +date based on our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowings outstanding under our term credit facility as of December 31, 2013 would increase our annual cash interest expense by +approximately $900,000. +We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling +operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations +will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition. +The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term +maturity of these items. +Item 8. +Financial Statements and Supplementary Data. +Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference. +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 9A. +Controls and Procedures. +Disclosure Controls and Procedures: +Under the supervision and with the +participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is +defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2013, our disclosure controls and +procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and +is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. +42 +Table of Contents +Management’s Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange +Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013, +based on the Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial +reporting was effective as of December 31, 2013. +The effectiveness of our internal control over financial reporting as of +December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of +this Report. +Changes in Internal Control over Financial Reporting: +There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have +materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +Item 9B. +Other Information. +None. +43 +Table of Contents +PART III +Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities +Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference. +Item 10. +Directors, Executive Officers and Corporate Governance. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive +officer and principal financial and accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com . We intend to disclose any amendments to or waivers from this code +on our website. +Item 11. +Executive Compensation. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +Item 14. +Principal Accounting Fees and Services. +The information required by this Item is incorporated herein by reference to the Proxy Statement. +44 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/item13.txt b/raw/filings/0000889900/2013/0001193125-14-054910/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..0cddff69e477bef9ebe48b2e286609648c8a086d --- /dev/null +++ b/raw/filings/0000889900/2013/0001193125-14-054910/item13.txt @@ -0,0 +1,3 @@ +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated herein by reference to the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/item9a.txt b/raw/filings/0000889900/2013/0001193125-14-054910/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b18a8c3c65eefbfc7f1d5aeb3b0e04fcfd1f5564 --- /dev/null +++ b/raw/filings/0000889900/2013/0001193125-14-054910/item9a.txt @@ -0,0 +1,21 @@ +Item 9A. +Controls and Procedures. +Disclosure Controls and Procedures: +Under the supervision and with the +participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is +defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2013, our disclosure controls and +procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and +is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. +42 +Table of Contents +Management’s Report on Internal Control over Financial Reporting: +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange +Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013, +based on the Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial +reporting was effective as of December 31, 2013. +The effectiveness of our internal control over financial reporting as of +December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of +this Report. +Changes in Internal Control over Financial Reporting: +There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have +materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/rp_note.txt b/raw/filings/0000889900/2013/0001193125-14-054910/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000889900/2013/0001193125-14-054910/rpt_disclosure.txt b/raw/filings/0000889900/2013/0001193125-14-054910/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391