10-K/A 1 h09326a1e10vkza.txt PATTERSON-UTI ENERGY, INC.- AMENDMENT NO.1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM 10-K/A (AMENDMENT NO. 1) --------------------- (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: (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 [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 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: Portions of the Definitive Proxy Statement for the 2003 Annual Meeting of Stockholders filed by the registrant with the Securities and Exchange Commission on March 24, 2003 (Part III) -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- EXPLANATORY NOTE We are filing this Amendment No. 1 to our Annual Report on Form 10-K in response to comments received by us from the Staff of the Securities and Exchange Commission. Unless otherwise stated, all information contained in this amendment is as of February 7, 2003, the filing date of our original Annual Report on Form 10-K for the fiscal year ended December 31, 2002. --------------------- This Report on Form 10-K/A (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/A, 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. 1 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. 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, 2 - 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. During fiscal years 2002, 2001, and 2000, we capitalized approximately $65 million, $151 million, and $117 million, respectively, 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, 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 3 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, 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 Standardized measure of discounted future net cash flows(1).............................................. $21,100 $10,714 $16,640
--------------- (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 (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. 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.
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)......................... $ 5.11 $ 5.32 $ 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 2002. One or more completions in the same well bore are reflected as one well.
PRODUCTIVE WELLS ------------- GROSS NET ----- ----- Oil......................................................... 147 32.88 Gas......................................................... 158 19.99 --- ----- Total............................................. 305 52.87 === =====
7 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 2002:
DEVELOPED ACREAGE UNDEVELOPED ACREAGE ------------------ -------------------- LOCATION GROSS NET GROSS NET -------- ------- ------- -------- -------- Texas........................................... 57,590 10,219 48,017 9,840 Kansas.......................................... 320 45 -- -- New York........................................ 160 131 -- -- New Mexico...................................... 3,639 443 601 96 Mississippi..................................... 2,000 306 20,000 4,400 Ohio............................................ 880 86 -- -- Pennsylvania.................................... 880 129 -- -- ------ ------ ------ ------ Total................................. 65,469 11,359 68,618 14,336 ====== ====== ====== ======
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 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, 2003........................................... 5,367 1,262 December 31, 2004........................................... 4,871 1,123 December 31, 2005 and later................................. 58,380 11,951 ------ ------ Total............................................. 68,618 14,336 ====== ======
DRILLING ACTIVITIES -- The following table sets forth the results of our participation in the drilling of developmental and exploratory wells during 2000, 2001 and 2002:
DEVELOPMENTAL WELLS EXPLORATORY WELLS ---------------------------- --------------------------- PRODUCTIVE DRY HOLES PRODUCTIVE DRY HOLES ------------- ------------ ------------ ------------ YEAR ENDED DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET ----------------------- ----- ----- ----- ---- ----- ---- ----- ---- 2000.................................. 16 3.63 14 3.33 4 0.50 3 0.57 2001.................................. 20 3.82 5 1.06 5 0.87 2 0.56 2002.................................. 24 4.17 11 2.67 6 0.56 1 0.25 -- ----- -- ---- -- ---- -- ---- Total....................... 60 11.62 30 7.06 15 1.93 6 1.38 == ===== == ==== == ==== == ====
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. 8 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. 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, 9 - 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, 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 10 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 - 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, 11 - 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 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 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 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 (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, 12 - 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, - 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 13 Patterson Petroleum LP under the letter agreement in the amount of approximately $5,075,000. 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 or results of operations. 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. 14 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/A, 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 15 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 16 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 17 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. 18 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 sales prices of our common shares for the periods indicated:
HIGH LOW ------ ------ 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 2001: First quarter............................................... $41.38 $28.62 Second quarter.............................................. 36.83 16.01 Third quarter............................................... 19.49 11.06 Fourth quarter.............................................. 25.73 11.80
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 19 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
20
YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2002 2001 2000 1999 1998 -------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Income tax expense (benefit)............ 1,670 102,333 22,878 (4,766) 5,328 -------- -------- -------- -------- -------- 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, 21 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. 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 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 2002, 2001 or 2000. 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 paragraph 31(b) of SFAS 19, costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. Capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs, and intangible development costs, are 22 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. 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 (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. 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 23 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 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. 24 (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 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. 25 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 26 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. 27
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 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. 28 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)%
29 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. 30
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 31 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 32 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/A, 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 Annual Report on Form 10-K/A, 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, 2002) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 33 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The information required by this Item is incorporated herein by reference to the information appearing under the captions "Proposal No. 1 -- Election of Directors", "Executive Officers" and "Other Matters -- Section 16(a) Beneficial Ownership Reporting Compliance" in the Definitive Proxy Statement filed by the Company with the Securities and Exchange Commission on March 24, 2003 (the "Proxy Statement"). ITEM 11. EXECUTIVE COMPENSATION. The information required by this Item is incorporated herein by reference to the information appearing under the captions "Proposal No. 1 -- Election of Directors -- Compensation of Directors", "Summary Compensation Table", "Options Granted During Fiscal Year 2002", "Aggregated Option Exercises in 2002 and Value Table at December 31, 2002", "Employment Contracts and Change-in-Control Arrangements" and "Compensation Committee Interlocks and Insider Participation" in 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 information appearing under the captions "Proposal No. 2 -- Amendment to 1997 Long-Term Incentive Plan -- Summary Information Pertaining to All Stock Option and Related Plans of Patterson-UTI" and "Security Ownership of Principal Stockholders and Management" in the Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information required by this Item is incorporated herein by reference to the information appearing under the caption "Certain Transactions" in the Proxy Statement. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. This information is not required to be disclosed in this Annual Report on Form 10-K/A pursuant to the SEC's Final Rule Release No. 33-8183, dated January 28, 2003. 34 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 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, as amended.(4) 3.2 Amended and Restated Bylaws.(5) 4.1 Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company.(6) 4.2 Amendment to Rights Agreement dated as of October 23, 2001.(7) 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.(5) 4.5 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as amended.(8)* 4.6 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock Option Plan, as amended.(9)* 4.7 Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan.(4)* 4.8 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(4)* 4.9 Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan.(10)* 4.10 1997 Stock Option Plan of DSI Industries, Inc.(11)* 4.11 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)* 10.1 For additional material contracts, see Exhibits 4.1, 4.2 and 4.4 through 4.11. 10.2 Amended and Restated Loan and Security Agreement, dated July 26, 2002.(12) 10.3 Revolving Loan Promissory Note, dated July 26, 2002.(12) 10.4 Amended and Restated Guaranty Agreement, dated July 26, 2002.(12) 10.5 Amended and Restated Pledge Agreement, dated July 26, 2002.(12) 10.6 Model Form Operating Agreement.(13) 10.7 Form of Drilling Bid Proposal and Footage Drilling Contract.(13) 10.8 Form of Turnkey Drilling Agreement.(13) 21.1 Subsidiaries of the Registrant.(14) 23.1 Consent of Independent Auditors -- PricewaterhouseCoopers LLP. 23.2 Consent of Independent Auditors -- Ernst & Young LLP. 23.3 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.
35 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 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 6, "Exhibits and Reports on Form 8-K" to Form 10-Q for the quarterly period ended June 30, 2003. (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 8, "Exhibits" to Registration Statement on Form S-8 (File No. 333-39471) filed on March 13, 1998. (9) Incorporated herein by reference to Item 8, "Exhibits" to Registration Statement on Form S-8 (File No. 333-39471) filed on November 4, 1997. (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 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. (13) 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. (14) Incorporated herein by reference to Item 15, "Exhibits, Financial Statement Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the fiscal year ended December 31, 2002. * 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. 36 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ------- Report of Independent Auditors; 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 AUDITORS 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 -- 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 (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. 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 paragraph 31(b) of SFAS 19, costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs, and intangible development costs, are depreciated, depleted, and amortized on the units-of-production method, based on petroleum engineer estimates of proved oil and natural gas reserves of each respective field. 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 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 F-10 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 ===== ===== =====
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 F-11 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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," 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. F-12 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 an acquisition of assets and the 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. The transaction was accounted for as an acquisition of assets and 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, F-13 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) - costs of $1.4 million incurred in connection with changes to the Company's credit facilities (see Note 8), 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 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 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 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. The transactions were accounted for as acquisitions of assets and 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 transaction was accounted for as a business combination and 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 transactions were accounted for as acquisitions of assets and 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 transaction was accounted for as an acquisition of assets and 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. F-14 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The transaction was accounted for as an acquisition of assets and 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 acquired assets consisted of fourteen land drilling rigs and related equipment. The acquisition was accounted for as a business combination and 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 transaction was accounted for as an acquisition of assets and 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.............................. 49,736 45,839 Buildings................................................... 11,073 10,357 Land........................................................ 3,779 3,703 ---------- -------- 1,014,501 917,010 Less accumulated depreciation and depletion................. (386,767) (302,590) ---------- -------- $ 627,734 $614,420 ========== ========
F-15 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 ======= =======
The amount of goodwill and other intangible assets as of December 31, 2002 and 2001 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): 2002 Contract Drilling: Goodwill...................... $56,543.. Accumulated Amortization........ $16,278 Non-Competes & Other.......... $ 1,909 Accumulated Amortization........ $ 828 Drilling and Completion Fluids: Goodwill...................... $13,317 Accumulated Amortization........ $ 3,383 Non-Competes & Other.......... $ 47 Accumulated Amortization........ $ 14 2001 Contract Drilling: Goodwill...................... $56,543 Accumulated Amortization........ $16,278 Non-Competes & Other.......... $ 3,588 Accumulated Amortization........ $ 2,189 Drilling and Completion Fluids: Goodwill...................... $13,317 Accumulated Amortization........ $ 3,383 Non-Competes & Other.......... $ 47 Accumulated Amortization........ $ 11
F-16 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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
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 ====== ======== =======
F-17 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 ======= =======
F-18 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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. F-19 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 or results of operations. 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. 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 F-20 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $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). 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. F-21 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) - 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. 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 segments: contract drilling of oil and natural gas wells, 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. 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 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 F-26 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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(a)................. (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 ======== ======== ========
--------------- (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 primarily related to the contract drilling segment. 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) OIL AND GAS EXPENDITURES AND CAPITALIZED COSTS Gross oil and natural gas expenditures by the Company for the years ended December 31, 2002, 2001 and 2000 are summarized below (in thousands):
2002 2001 2000 ------ ------- ------ Property acquisition costs............................... $ 905 $ 3,813 $ 798 Exploration costs........................................ 6,267 6,788 5,401 Development costs........................................ 845 1,354 1,012 ------ ------- ------ $8,017 $11,955 $7,211 ====== ======= ======
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, 2001 and 2000 are comprised of the following (in thousands):
2002 2001 2000 -------- -------- -------- Proved properties................................... $ 44,849 $ 43,500 $ 37,709 Accumulated depreciation and depletion.............. (35,684) (35,828) (28,338) -------- -------- -------- $ 9,165 $ 7,672 $ 9,371 ======== ======== ========
RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES: Oil and natural gas sales........................... $ 12,738 $ 13,842 $ 13,619 Gain on sale of oil and natural gas properties...... 303 213 4 -------- -------- -------- 13,041 14,055 13,623 -------- -------- -------- Costs and expenses: Lease operating and production costs................ 3,068 3,978 3,245 Exploration costs including dry holes and abandonments...................................... 785 1,038 1,627 Depreciation and depletion.......................... 4,633 6,317 3,601 Impairment of oil and natural gas properties........ 727 1,100 -- -------- -------- -------- 9,213 12,433 8,473 -------- -------- -------- Results of operations for oil and natural gas producing activities, before taxes................ $ 3,828 $ 1,622 $ 5,150 ======== ======== ========
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 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, 2002 were $31.20 per Bbl of oil and $4.789 per Mcf of natural gas. Estimates of reserves and production performance are subjective and may change materially as actual production information becomes available. 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) 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. 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: December 30, 2003 By: /s/ CLOYCE A. TALBOTT --------------------------------------------- Cloyce A. Talbott Chief Executive Officer
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, as amended.(4) 3.2 Amended and Restated Bylaws.(5) 4.1 Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company.(6) 4.2 Amendment to Rights Agreement dated as of October 23, 2001.(7) 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.(5) 4.5 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as amended.(8)* 4.6 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock Option Plan, as amended.(9)* 4.7 Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan.(4)* 4.8 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(4)* 4.9 Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan.(10)* 4.10 1997 Stock Option Plan of DSI Industries, Inc.(11)* 4.11 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)* 10.1 For additional material contracts, see Exhibits 4.1, 4.2 and 4.4 through 4.11. 10.2 Amended and Restated Loan and Security Agreement, dated July 26, 2002.(12) 10.3 Revolving Loan Promissory Note, dated July 26, 2002.(12) 10.4 Amended and Restated Guaranty Agreement, dated July 26, 2002.(12) 10.5 Amended and Restated Pledge Agreement, dated July 26, 2002.(12) 10.6 Model Form Operating Agreement.(13) 10.7 Form of Drilling Bid Proposal and Footage Drilling Contract.(13) 10.8 Form of Turnkey Drilling Agreement.(13) 21.1 Subsidiaries of the Registrant.(14) 23.1 Consent of Independent Auditors -- PricewaterhouseCoopers LLP. 23.2 Consent of Independent Auditors -- Ernst & Young LLP. 23.3 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 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 6, "Exhibits and Reports on Form 8-K" to Form 10-Q for the quarterly period ended June 30, 2003. (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 8, "Exhibits" to Registration Statement on Form S-8 (File No. 333-39471) filed on March 13, 1998. (9) Incorporated herein by reference to Item 8, "Exhibits" to Registration Statement on Form S-8 (File No. 333-39471) filed on November 4, 1997. (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 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. (13) 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. (14) Incorporated herein by reference to Item 15, "Exhibits, Financial Statement Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the fiscal year ended December 31, 2002. * Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.