-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KF4LhQ1tkAPzD67OnA6mkC+73H40HdFQ+MU7C93KKHTHCDtwMt1T/LfaZOYyhRRl oouUnNDkHe0kbBvqymnwdg== 0000950134-01-509830.txt : 20020413 0000950134-01-509830.hdr.sgml : 20020413 ACCESSION NUMBER: 0000950134-01-509830 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20010930 FILED AS OF DATE: 20011227 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HELMERICH & PAYNE INC CENTRAL INDEX KEY: 0000046765 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 730679879 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04221 FILM NUMBER: 1823191 BUSINESS ADDRESS: STREET 1: UTICA AT 21ST ST CITY: TULSA STATE: OK ZIP: 74114 BUSINESS PHONE: 9187425531 MAIL ADDRESS: STREET 1: UTICA AT 21ST ST CITY: TULSA STATE: OK ZIP: 74114 10-K 1 d93048e10-k.txt FORM 10-K FOR FISCAL YEAR END SEPTEMBER 30, 2001 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2001 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 1-4221 HELMERICH & PAYNE, INC. (Exact name of registrant as specified in its charter) DELAWARE 73-0679879 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification no.) UTICA AT TWENTY-FIRST STREET, TULSA, OKLAHOMA 74114 (Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (918) 742-5531 Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED ------------------- ------------------------------------ Common Stock ($0.10 par value) New York Stock Exchange Common Stock Purchase Rights New York Stock Exchange
Securities registered Pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. [ ] At December 14, 2001, the aggregate market value of the voting stock held by non-affiliates was $1,402,779,905. Number of shares of common stock outstanding at December 14, 2001: 49,859,297. DOCUMENTS INCORPORATED BY REFERENCE (1) Annual Report to Shareholders for the fiscal year ended September 30, 2001 -- Parts I, II, and IV. (2) Proxy Statement for Annual Meeting of Security Holders to be held March 6, 2002 -- Part III. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT'S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY", "WILL", "EXPECT", "INTEND", "ESTIMATE", "ANTICIPATE", "BELIEVE", OR "CONTINUE" OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT'S EXPECTATIONS ARE DISCLOSED IN ITEM 1. BUSINESS "REGULATIONS AND HAZARDS", AND "MARKET FOR OIL AND GAS", AS WELL AS IN MANAGEMENT'S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 10 THROUGH 17 IN REGISTRANT'S ANNUAL REPORT TO THE SHAREHOLDERS FOR FISCAL 2001 AND IN THE REMAINDER OF THIS REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. HELMERICH & PAYNE, INC. AND SUBSIDIARIES Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 2001 PART I Item 1. BUSINESS Helmerich & Payne, Inc. (the "Registrant"), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. Registrant is primarily engaged in the exploration, production, and sale of crude oil and natural gas and in contract drilling of oil and gas wells for others. These activities account for the major portion of its operating revenues. The Registrant is also engaged in the ownership, development, and operation of commercial real estate. The Registrant is organized into three separate autonomous operating divisions being contract drilling; oil & gas exploration and production operations; and real estate. While there is a limited amount of intercompany activity, each division operates essentially independently of the others. Each of the divisions, except exploration and production, conducts their respective business through wholly owned subsidiaries. Operating decentralization is balanced by a centralized finance division, which handles all accounting, data processing, budgeting, insurance, cash management, and related activities. Most of the Registrant's current exploration efforts are concentrated in Louisiana, Oklahoma, Texas, and the Hugoton Field of western Kansas. The Registrant also explores from time to time in the Rocky Mountain area, New Mexico, Alabama, Michigan, and Mississippi. Substantially all of the Registrant's gas production is sold to and resold by its marketing subsidiary. This subsidiary also purchases gas from unaffiliated third parties for resale. The Registrant's domestic contract drilling is conducted primarily in Oklahoma, Texas, Wyoming, and Louisiana, and offshore from platforms in the Gulf of Mexico and offshore California. The Registrant has also operated during fiscal 2001 in six international locations: Venezuela, Ecuador, Colombia, Argentina, Bolivia and Equatorial Guinea. The Registrant's real estate investments are located in Tulsa, Oklahoma, where the Registrant has its executive offices. CONTRACT DRILLING The Registrant believes that it is one of the major land and offshore platform drilling contractors in the western hemisphere. Operating principally in North and South America, the Registrant specializes primarily in deep drilling in major gas producing basins of the United States and in drilling for oil and gas in remote international areas. For its international operations, the Registrant operates certain rigs which are transportable by helicopter. In the United States, the Registrant draws its customers primarily from the major oil companies and the larger independents. The Registrant also drills for its own oil and gas division. In South America, the Registrant's current customers include the Venezuelan state petroleum company and major international oil companies. In fiscal 2001, Registrant received approximately 45% of its consolidated revenues from the Registrant's ten largest contract drilling customers. BP and Shell Oil Co., including their affiliates, (respectively, "BP" and "Shell") are the Registrant's two largest contract drilling customers. The I - 2 Registrant performs drilling services for BP and Shell on a world-wide basis. Revenues from drilling services performed for BP and Shell in fiscal 2001 accounted for approximately 15% and 8%, respectively, of the Registrant's consolidated revenues for the same period. While the Registrant believes that its relationship with all of these customers is good, the loss of BP or Shell or a simultaneous loss of several of its larger customers would have a material adverse effect on the drilling subsidiary and the Registrant. The Registrant provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided so that Registrant's customers may explore for and develop oil and gas from onshore areas and from fixed and tension leg platforms in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drillstring, and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A land drilling rig may be moved from location to location without modification to the rig. Conversely, a platform rig is specifically designed to perform drilling operations upon a particular platform. While a platform rig may be moved from its original platform, significant expense is incurred to modify a platform rig for operation on each subsequent platform. In addition to traditional platform rigs, Registrant operates self-moving minimum space platform drilling rigs and drilling rigs to be used on tension leg platforms. The minimum space rig is designed to be moved without the use of expensive derrick barges. The tension leg platform rig allows drilling operations to be conducted in much deeper water than traditional fixed platforms. A helicopter rig is one that can be disassembled into component part loads of approximately 4,000-20,000 pounds and transported to remote locations by helicopter, cargo plane, or other means. I - 3 The Registrant's workover rigs are equipped with engines, drawworks, a mast, pumps, and blowout preventers. A workover rig is used to complete a new well after the hole has been drilled by a drilling rig, and to remedy various downhole problems that occur in producing wells. During fiscal 1998, Registrant put to work a new generation of six highly mobile/depth flexible new rigs (individually the "FlexRig"TM). The FlexRig has the potential to reduce rig move times by at least 50%. In addition, the FlexRig allows a greater depth flexibility of between 8,000 to 18,000 feet and provides greater operating efficiency. During fiscal 2000, the Registrant ordered 12 new FlexRigs at an approximate cost of between $7.5 million and $8.25 million each. The Registrant took delivery of nine new FlexRigs through October 2001, and expects the final three FlexRigs to be delivered by the end of calendar 2001. During fiscal 2001, the Registrant ordered an additional 25 new FlexRigs at an approximate cost of $10 million each. These new rigs are the next generation of FlexRigs which incorporate new drilling technology and new safety design. The FlexRigs will be available for work in the Registrant's domestic and international drilling operations. The Registrant expects that approximately 15 of these next generation rigs will be delivered between March and September, 2002, with the remaining rigs expected to be delivered by the end of fiscal 2003. The Registrant's drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and sometimes cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract. Most of the contracts are performed on a "daywork" basis, under which the Registrant charges a fixed rate per day, with the price determined by the location, depth, and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. The Registrant has previously performed contracts on a combination "footage" and "daywork" basis, under which the Registrant charged a fixed rate per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the I - 4 remainder of the hole. Contracts performed on a "footage" basis involve a greater element of risk to the contractor than do contracts performed on a "daywork" basis. Also, the Registrant has previously accepted "turnkey" contracts under which the Registrant charges a fixed sum to deliver a hole to a stated depth and agrees to furnish services such as testing, coring, and casing the hole which are not normally done on a "footage" basis. "Turnkey" contracts entail varying degrees of risk greater than the usual "footage" contract. Registrant did not accept a "footage" or "turnkey" contract during fiscal 2001. The Registrant believes that under current market conditions "footage" and "turnkey" contract rates do not adequately compensate contractors for the added risks. The duration of the Registrant's drilling contracts are "well-to-well" or for a fixed term. "Well-to-well" contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts customarily provide for termination at the election of the customer, with an "early termination payment" to be paid to the contractor if a contract is terminated prior to the expiration of the fixed term. While current fixed term contracts are for one to five year periods, some fixed term and well-to-well contracts are expected to be continued for longer periods than the original terms. However, the contracting parties have no legal obligation to extend the contracts. Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to the Registrant and the customer. In most instances contracts provide for additional payments for mobilization and demobilization. Contracts for work in foreign countries generally provide for payment in United States dollars, except for amounts required to meet local expenses. However, government owned petroleum companies are more frequently requesting that a greater proportion of these payments be made in local currencies. See Regulations and Hazards, page I-8. I - 5 Domestic Drilling The Registrant believes it is a major land and offshore platform drilling contractor in the domestic market. At the end of September, 2001, the Registrant had 59 of its rigs (49 land rigs and 10 platform rigs) operating in the United States and had management contracts for three customer-owned rigs. The 11 rig increase from fiscal 2000 to 2001 is due to the delivery of seven new FlexRigs, transfer of three rigs from Registrant's international operations, and the assembly of one rig from existing components. During fiscal 2001, Registrant was awarded one term contract for the construction and operation of one self-moving platform rig in the Gulf of Mexico for a major oil company. Registrant expects that this rig will commence drilling operations during calendar year 2002. Also, during fiscal 2001, Registrant signed a letter of intent for the construction and operation of one self-moving platform rig in the Gulf of Mexico for another major oil company. If a contract is awarded, it is expected that drilling operations would commence during calendar year 2002. International Drilling The Registrant's international drilling operations began in 1958 with the acquisition of the Sinclair Oil Company's drilling rigs in Venezuela. Helmerich & Payne de Venezuela, C.A., a wholly owned subsidiary of the Registrant, is one of the leading drilling contractors in Venezuela. Beginning in 1972, with the introduction of its first helicopter rig, the Registrant expanded into other Latin American countries. Venezuelan operations continue to be a significant part of the Registrant's operations. At the end of fiscal 2001, the Registrant owned and operated 14 land drilling rigs in Venezuela with a utilization rate of 37% for such fiscal year. The Registrant worked for the Venezuelan state petroleum company during fiscal 2001, and revenues from this work accounted for approximately 3.5% of the I - 6 Registrant's consolidated revenues during the fiscal year. During fiscal year 2001, Registrant moved three rigs from Venezuela to Houston, Texas, for modifications and upgrades. Registrant's rig utilization rate in Venezuela has increased from approximately 32% during the 2000 fiscal year to approximately 37% in fiscal 2001. Even though the Registrant is, at this time, unable to predict future fluctuations in its utilization rates during fiscal 2002, the Registrant believes that the prospects are good for returning at least three of its idle rigs back to work during fiscal 20021. The Venezuelan government, in early 1996, permitted foreign exploration and production companies to acquire rights to explore for and produce oil and gas in Venezuela. Registrant has performed contract drilling services in Venezuela for three independent oil companies during fiscal 2001. At the end of fiscal 2001, the Registrant owned and operated seven rigs in Ecuador. The Registrant's utilization rate was 92% during fiscal 2001. Revenues generated by Ecuadorian drilling operations contributed approximately 4.3% of the Registrant's consolidated revenue. The contracts are with large international oil companies. During fiscal 2001, one rig was moved into Ecuador from Venezuela. At the end of fiscal 2001, the Registrant owned and operated three drilling rigs in Colombia. The Registrant's utilization rate in Colombia was 69% during fiscal 2001. During fiscal 2001 the revenues generated by Colombian drilling operations contributed approximately 3.3% of the Registrant's consolidated revenues. During fiscal 2001, the Registrant moved four rigs from Colombia to Houston, Texas, for modifications and upgrades. The Registrant expects continued reduction in activity and revenues from Colombia. I - 7 In addition to its operations in Venezuela, Ecuador and Colombia, the Registrant in fiscal 2001 owned and operated six rigs in Bolivia and two rigs in Argentina. In Bolivia and Argentina, the contracts are with large international oil companies. During fiscal 2001, the Registrant continued operations under a management contract for a customer-owned platform rig located offshore Equatorial Guinea. Competition The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, rig availability, efficiency, condition of equipment, reputation, and customer relations. Competition is primarily on a regional basis and may vary significantly by region at any particular time. Land drilling rigs can be readily moved from one region to another in response to changes in levels of activity, and an oversupply of rigs in any region may result. Although many contracts for drilling services are awarded based solely on price, the Registrant has been successful in establishing long-term relationships with certain customers which have allowed the Registrant to secure drilling work even though the Registrant may not have been the lowest bidder for such work. The Registrant has continued to attempt to differentiate its services based upon its engineering design expertise, operational efficiency, safety and environmental awareness. Regulations and Hazards The drilling operations of the Registrant are subject to the many hazards inherent in the business, including blowouts and well fires. These hazards could cause personal injury, suspend drilling operations, seriously damage or destroy the equipment involved, and cause substantial damage to producing formations and the surrounding areas. The Registrant believes that it has adequate insurance coverage for comprehensive general liability, public liability, property damage (including insurance against loss by fire and storm, blowout, I - 8 and cratering risks), workers compensation and employer's liability. No insurance is carried against loss of earnings or business interruption. The Registrant is unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, the Registrant is generally indemnified under its drilling contracts from this risk. The majority of the Registrant's insurance coverage has been purchased through fiscal 2002, however, rates and deductibles increased substantially for a number of coverages due to general hardening in the energy insurance market as well as the events of September 11, 2001. In view of these present conditions, no assurance can be given that all or a portion of the Registrant's coverage will not be cancelled during fiscal 2002 nor that insurance coverage will continue to be available at rates considered reasonable. International operations are subject to certain political, economic, and other uncertainties not encountered in domestic operations, including increased risks of terrorism, expropriation of equipment as well as expropriation of a particular oil company operator's property and drilling rights, taxation policies, foreign exchange restrictions, currency rate fluctuations, and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. There can be no assurance that there will not be changes in local laws, regulations, and administrative requirements or the interpretation thereof which could have a material adverse effect on the profitability of the Registrant's operations or on the ability of the Registrant to continue operations in certain areas. Because of the impact of local laws, the Registrant's future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which the Registrant holds only a minority interest, or pursuant to arrangements under which the Registrant conducts operations under contract to local entities. While the Registrant believes that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on the Registrant's operations or revenues, there can be no assurance that the Registrant will in all I - 9 cases be able to structure or restructure its operations to conform to local law (or the administration thereof) on terms acceptable to the Registrant. The Registrant further attempts to minimize the potential impact of such risks by operating in more than one geographical area and by attempting to obtain indemnification from operators against expropriation, nationalization, and deprivation. During fiscal 2001, approximately 18.7% of the Registrant's consolidated revenues were generated from the international contract drilling business. Approximately 93% of the international revenues were from operations in South America and 51% of South American revenues were from Venezuela and Ecuador. Exposure to potential losses from currency devaluation is minimal in Colombia, Ecuador, Bolivia and Argentina. In those countries, all receivables and payments are currently in U.S. dollars. Cash balances are kept at a minimum which assists in reducing exposure. In Venezuela, approximately 50% of the Registrant's invoice billings are in U.S. dollars and the other 50% are in the local currency, the bolivar. The Registrant is exposed to risks of currency devaluation in Venezuela as a result of bolivar receivable balances and necessary bolivar cash balances. In 1994, the Venezuelan government established a fixed exchange rate in hopes of stemming economic problems caused by a high rate of inflation. During the first week of December, 1995, the government established a new exchange rate, resulting in further devaluation of the bolivar. In April of 1996, the bolivar was again devalued when the government decided to abolish its fixed rate policy and to allow a floating market exchange rate. During fiscal 2000, the Registrant experienced losses of approximately US$687,000 and in fiscal 2001 it experienced losses of US$796,000 as a result of the devaluation of the bolivar. Registrant is unable to predict future devaluation in Venezuela. In the event that fiscal 2002 activity levels are similar to fiscal 2001 and if a 25% to 50% devaluation would occur, the Registrant could experience potential currency valuation losses ranging from approximately US$1,600,000 to US$2,600,000. I - 10 During the mid-1970s, the Venezuelan government nationalized the exploration and production business. At the present time it appears the Venezuelan government will not nationalize the contract drilling business. Any such nationalization could result in Registrant's loss of all or a portion of its assets and business in Venezuela. Many aspects of the Registrant's operations are subject to government regulation, including those relating to drilling practices and methods and the level of taxation. In addition, various countries (including the United States) have environmental regulations which affect drilling operations. Drilling contractors may be liable for damages resulting from pollution. Under United States regulations, drilling contractors must establish financial responsibility to cover potential liability for pollution of offshore waters. Generally, the Registrant is indemnified under drilling contracts from liability arising from pollution, except in certain cases of surface pollution. However, the enforceability of indemnification provisions in foreign countries may be questionable. The Registrant believes that it is in substantial compliance with all legislation and regulations affecting its operations in the drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance has not materially affected the capital expenditures, earnings, or competitive position of the Registrant, although these measures may add to the costs of operating drilling equipment in some instances. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on operations cannot be predicted. OIL & GAS EXPLORATION AND PRODUCTION OPERATIONS The Registrant engages in the origination of prospects; the identification, acquisition, exploration, and development of prospective and proved oil and gas properties; the production and sale of crude oil, condensate, and natural gas; and the marketing of natural gas. The Registrant I - 11 considers itself a medium-sized independent producer. All of the Registrant's oil and gas operations are conducted in the United States. Most of the Registrant's current exploration and drilling effort is concentrated in Oklahoma, Kansas, Texas, and Louisiana. The Registrant also explores from time to time in New Mexico, Alabama, Michigan, Mississippi, and the Rocky Mountain area. The Registrant's exploration and production division includes geographical exploitation/exploration teams comprised of geological, engineering, and land personnel. These personnel primarily develop in-house oil and gas prospects as well as review outside prospects and acquisitions for their respective geographical areas. The Registrant believes that this structure allows each team to gain greater expertise in its respective geographical area and reduces risk in the development of prospects. The Registrant has been focusing on developing prospects using 3D seismic technology. Currently, the Registrant is involved in 3D surveys covering more than 1,480 square miles, of which approximately 1,180 square miles are proprietary. Approximately 1,100 square miles of land covered by such surveys is located near the Texas and Louisiana onshore Gulf Coast. Registrant's exploration and development program has covered a range of prospects, from shallow "bread and butter" programs to deep, expensive, high risk/high return wells. The Registrant continued its drilling program in Oklahoma, Kansas, west Texas, south Texas and south Louisiana, participating in a total of 123 wells during fiscal 2001. Of the 123 well total, 47 wells were development wells drilled in areas where reserves were previously booked, and 29 wells were dry holes. Registrant increased its development of proved undeveloped reserves in fiscal 2001 as the result of high natural gas prices during the last half of calendar 2000. The focus of this drilling was the Redfork play in western Oklahoma, additional I - 12 development of Ashland Field in southeastern Oklahoma and the Hugoton Field in Kansas, as well as additional drilling in the panhandle of Texas and in southern Louisiana. Registrant's participation in these 47 development wells resulted in the addition of approximately 15.7 BCF of gas and 75,826 barrels of oil previously classified as proved undeveloped. Of the remaining 76 wells drilled during the year, 40 were wildcat wells, 20 of which were successfully completed. These drilling efforts resulted in new discoveries of approximately 12.8 BCF of gas and 1,145,195 barrels of oil and condensate. A total of $80,040,769 was spent in the Registrant's exploration and development program during fiscal 2001. This figure includes $7,838,770 of geophysical expense, but is exclusive of expenditures for acreage and acquisition of proved oil and gas reserves. The Registrant's total company-wide acquisition cost for acreage in fiscal 2001 was $18,611,957. The Registrant also spent $737,500 for the acquisition of proved oil and gas reserves during fiscal 2001. The reserves associated with these acquisitions were 495,888 MCF of gas and 434 barrels of oil. The Registrant's fiscal 2002 exploration and production budget has been reduced to approximately $50 million due to lower product prices, higher service company costs and high-grading of existing prospects in order to reduce finding costs. This is a 47.6% reduction from actual exploration and production expenditures in fiscal 2001. During fiscal 2001, the Registrant continued to work with its investment banker, Petrie Parkman & Co., to analyze strategic alternatives with regard to the Registrant's oil and gas division. It is contemplated that a successful transaction could, among other things, lead to the spinoff of the Company's exploration and production business and the subsequent merger of such business with a third party. The Registrant is unable to predict if and when such a transaction may occur. I - 13 Market for Oil and Gas The Registrant does not refine any of its production. The availability of a ready market for such production depends upon a number of factors, including the availability of other domestic production, price, crude oil imports, the proximity and capacity of oil and gas pipelines, and general fluctuations in supply and demand. The Registrant does not anticipate any unusual difficulty in contracting to sell its production of crude oil and natural gas to purchasers and end-users at prevailing market prices and under arrangements that are usual and customary in the industry. The Registrant and its subsidiary, Helmerich & Payne Energy Services, Inc., have successfully developed markets with end-users, local distribution companies, and natural gas brokers for gas produced from successful wildcat wells and development wells. Substantially all of Registrant's gas production is sold to and resold by Helmerich & Payne Energy Services, Inc. During fiscal 2001, the price that Registrant received for the sale of its natural gas has fluctuated. Registrant's average per MCF natural gas sales price in fiscal 2001 for each of the first through fourth quarters was $4.73, $6.49, $4.27 and $2.66, respectively. The Registrant is of the opinion that during the next 12 to 18 months, the natural gas market will continue to be characterized by high volatility and relatively lower or moderating prices as compared to the average prices of natural gas in fiscal 2001. Last year's record high natural gas prices spawned an increase of productive capacity and a dramatic increase in drilling. This increase in productive capacity combined with a slowing economy and record storage levels is expected to result in excess gas supplies for the next 12 to 18 months. During the next two to three years, Registrant believes that there will be a more balanced supply and demand of natural gas as the economy recovers and productive capacity continues to decline. In the long-term, natural gas prices will be impacted by the decline in deliverability of domestic supply; increased use of natural gas for electrical generation; a recovery of U.S. economic growth; the I - 14 increased usage and better management of natural gas storage; seasonal usage; fuel switching; usage of gas as a feed stock; and importation of gas from Canada and Mexico. All these factors will continue to influence the cyclical nature of the supply/demand balance and will continue to occur as drilling activity and productive capacity respond to the changing prices. Historically, the Registrant has had no long-term sales contracts for its crude oil and condensate production. The Registrant continues its practice of contracting for the sale of its Kansas and Oklahoma and portions of its west Texas crude oil for terms of six to twelve months in an attempt to assure itself of the best price in the area for crude oil production. During fiscal 2001, the price that Registrant received for the sale of its crude oil has steadily decreased. Registrant's average per barrel crude oil sales price in fiscal 2001 for each of the first through fourth quarters was $31.44, $28.09, $26.12 and $25.33, respectively. Mid-East tensions, disputes among OPEC and non-OPEC countries over production quotas, and sluggish economies have created a continued mixed market in crude oil trading. Although a change in any of these factors could dramatically affect pricing, it is anticipated that crude oil prices may remain in the low $20's over the coming year. Competition The Registrant competes with numerous other companies and individuals in the acquisition of oil and gas properties and the marketing of oil and gas. The Registrant believes that it should continue to prepare for increased exploration activity without committing to a definite drilling timetable. The Registrant also believes that competition for the acquisition of gas producing properties will continue. Considering the Registrant's conservative acquisition strategy, the Registrant believes that it may be unable to acquire significant proved developed producing reserves from third parties. The Registrant intends to continue its review of properties in areas where the Registrant has expertise. The I - 15 Registrant's competitors include major oil companies, other independent oil companies, and individuals. Many of these competitors have financial resources, staffs, and facilities substantially larger than those of the Registrant. The effect of these competitive factors on the Registrant cannot be predicted. Title to Oil and Gas Properties The Registrant undertakes title examination and performs curative work at the time properties are acquired. The Registrant believes that title to its oil and gas properties is generally good and defensible in accordance with standards acceptable in the industry. Oil and gas properties in general are subject to customary royalty interests contracted for in connection with the acquisitions of title, liens incident to operating agreements, liens for current taxes, and other burdens and minor encumbrances, easements, and restrictions. The Registrant believes that the existence of such burdens will not materially detract from the general value of its leasehold interests. Governmental Regulation in the Oil and Gas Industry The Registrant's domestic operations are affected from time to time in varying degrees by political developments and federal and state laws and regulations. In particular, oil and gas production operations and economics are affected by price control, tax, and other laws relating to the petroleum industry; by changes in such laws; and by constantly changing administrative regulations. Most states in which the Registrant conducts or may conduct oil and gas activities regulate the production and sale of oil and natural gas, including regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled, and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the I - 16 ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas the Registrant can produce from its wells, and to limit the number of wells or locations at which the Registrant can drill. In addition, legislation affecting the natural gas and oil industry is under constant review. Inasmuch as such laws and regulations are frequently expanded, amended, or reinterpreted, the Registrant is unable to predict the future cost or impact of complying with such regulations. The Registrant believes that compliance with existing federal, state and local laws, rules and regulations will not have a material adverse effect upon its capital expenditures, earnings or competitive position. Regulatory Controls Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated under the Natural Gas Act ("NGA") and the regulations promulgated thereunder. Furthermore, the various states have regulated the production of natural gas and the gathering of natural gas, i.e., those activities which are not subject to Federal jurisdiction. Specifically, as to sales by the Registrant, under the NGA prior to November 1978 the Federal Power Commission and its successor, the Federal Energy Regulatory Commission ("FERC"), established ceiling prices for sales of natural gas for resale in interstate commerce by the Registrant. In November 1978, the U.S. Congress enacted the Natural Gas Policy Act ("NGPA") which adopted certain FERC ceiling prices and established additional price ceiling categories (such ceiling prices called maximum lawful prices - "MLPs"). In addition, the NGPA provided for a phased removal of certain ceiling prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act which provided a process for the phased decontrol of all first sales of natural gas, with complete removal of price ceilings on first sales by January 1, 1993. Since the Registrant believes that all of its sales of natural gas are first sales, such sales are no longer subject to Federal regulation. However, there may still be I - 17 issues of compliance with price ceilings as to prior periods. At this point, the only such issue, that the Registrant is aware of, relates to the Registrant's collection of reimbursement from certain interstate pipelines of Kansas ad valorem taxes paid by Registrant for sales prior to decontrol. Prior to decontrol of first sales, the Registrant made first sales to several interstate pipelines for which it received reimbursement for Kansas ad valorem taxes based upon the understanding (supported by prior agency case law) that such reimbursements were permitted under NGPA Section 110. In September 1997, FERC reversed its prior rulings and found that the Kansas ad valorem tax was not a tax which was reimbursable under Section 110 of the NGPA. Therefore, FERC found that to the extent that a producer collected an amount for a first sale in excess of the applicable MLP, as a result of reimbursement for Kansas ad valorem taxes, then such producer was required to make refunds, with interest, to the interstate pipeline purchaser which had paid the reimbursements. The pipeline was then required to disburse such refunds to its customers. Initially, reports of the affected pipelines listed refund liabilities of the Registrant based upon the total sales from wells which Registrant operated. Initial claims against the Registrant, as operator, totaled in excess of $13 million. During this period, Registrant estimated that its share of such refund liability totaled approximately $6.7 million. Subsequently, FERC issued clarifying orders providing that a producer was only responsible for refunds attributable to its own working interest ownership (and the related royalty interests) in production sold. Based upon that clarification, the interstate pipelines subsequently adjusted their refund claims to reflect only the respective producers' working interest share (with related royalty). Subsequently the pipelines made further adjustments to the claims based on corrected data. In response to the pipeline claims and prior to FERC's clarification as discussed above, the Registrant paid, under protest, approximately $1,379,000 to four interstate pipelines and placed I - 18 approximately $6,384,000 in an escrow account pending FERC's and the courts' decisions on various related legal issues and challenges. During calendar years 2000 and 2001, settlement negotiations have occurred among the affected pipelines, producers, and other interested parties. Settlement agreements resolving the refund claims have been reached in connection with four of the five pipelines which have made claims against the Registrant. Those settlements, with Colorado Interstate Gas Company, Northern Natural Gas Company, Williams Gas Pipelines Central, Inc. and Panhandle Eastern Pipe Line Company, are final and the settlement payments have been made by the Registrant out of the escrow account. Since the aggregate amount of the four settlements were less than the amounts escrowed for such liability, the Registrant, in May of 2001, was refunded approximately $3,240,252 of excess escrowed funds. A settlement in the fifth case, with Kinder Morgan Interstate Gas Transmission, LLC, is being negotiated. Based upon the total potential liability of the Registrant in the Kinder Morgan case, Registrant believes there is more than sufficient funds remaining in the Registrant's escrow account to cover any settlement liability therein. Commencing in 1992, FERC implemented a requirement that interstate pipelines must provide open access transportation of natural gas. Interstate pipelines have implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided the Registrant with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines. Under the NGA, natural gas gathering facilities are expressly exempt from FERC jurisdiction; what constitutes "gathering" under the NGA has evolved through FERC decisions and judicial review of such decisions. The Registrant believes that its gathering systems meet the test for non-jurisdictional "gathering" systems under the NGA. Therefore, the Registrant believes that its gathering facilities are I - 19 not subject to Federal NGA regulation. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services that are not Federally regulated under the NGA. Although exempt from Federal regulatory oversight, the Registrant's natural gas gathering systems and services may receive regulatory scrutiny by state agencies. In addition, the Registrant may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship the Registrant's gas to markets. In the past decade, FERC has approved the shift of certain interstate transmission facilities to unregulated gathering through the approval of abandonment of the jurisdictional facilities. The subsequent owner/operator of the gathering facilities may be an independent entity or an affiliate of the interstate pipeline company. This shift of a facility from a jurisdictional transmission facility to a non-jurisdictional gathering facility could result in the ability of the unregulated gathering entities to compete more effectively, and could result in changes in services and/or rates. It is not possible to predict the ultimate affect of these shifts on the Registrant's own gathering services or on the Registrant's use of third-party gathering/transmission facilities. In February, 1994, the Kansas Corporation Commission issued an order which modified allowables applicable to wells within the Hugoton Gas Field so that those proration units upon which infill wells had been drilled would be assigned a larger allowable than those units without infill wells. As a consequence of this order, the Registrant has participated in the drilling of 160 infill wells. Additional proposals and proceedings that might affect the oil and gas industry are pending before the U. S. Congress, FERC, state legislatures, state agencies, and the courts. The Registrant cannot predict when or whether any such proposals may become effective and what effect they will have on operations of the Registrant. Notwithstanding the foregoing, the Registrant does not anticipate that compliance with existing Federal, state and local laws, rules or regulations will have a I - 20 material adverse effect upon the capital expenditures, earnings or competitive position of the Registrant. Federal Income Taxation The Registrant's oil and gas operations, and the petroleum industry in general, are affected by certain federal income tax laws. The Registrant has considered the effects of such federal income tax laws on its operations and does not anticipate that there will be any material impact on the capital expenditures, earnings or competitive position of the Registrant. Environmental Laws The Registrant's activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Such laws and regulations may substantially increase the costs of exploring, developing, or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. In the opinion of the Registrant's management, its operations substantially comply with applicable environmental legislation and regulations. The Registrant believes that compliance with existing federal, state, and local laws, rules, and regulations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment will not have any material effect upon the capital expenditures, earnings, or competitive position of the Registrant. Natural Gas Marketing Helmerich & Payne Energy Services, Inc. ("HPESI") continues its emphasis on the purchase of the Registrant's natural gas production. In addition, HPESI purchases third-party gas for resale and provides compression, gathering services and processing for a fee. During fiscal year 2001, HPESI's sales of third-party gas constituted approximately 12% of the Registrant's consolidated revenues. I - 21 HPESI sells natural gas to markets in the Midwest and Rocky Mountain areas. HPESI's term gas sales contracts are for varied periods ranging from three months to seven years. However, recent contracts have tended toward shorter terms. The remainder of HPESI's gas is sold under spot market contracts having a duration of 30 days or less. For fiscal 2001, HPESI's term gas sales contracts provided for the sale of approximately 17 BCF of gas at prices which were indexed to market prices. For fiscal 2002, HPESI currently has approximately 7 BCF contracted at prices which are indexed to market prices. The balance of HPESI's gas is selling at spot prices or is not yet contracted. HPESI presently intends to fulfill such term sales contracts with a portion of the gas reserves purchased from the Registrant as well as from its purchases of third-party gas. See pages I-14 through I-21 regarding the market, competition, and regulation of natural gas. REAL ESTATE OPERATIONS The Registrant's real estate operations are conducted exclusively within the metropolitan area of Tulsa, Oklahoma. Its major holding is Utica Square Shopping Center, consisting of fifteen separate buildings, with parking and other common facilities covering an area of approximately 30 acres. Fourteen of these buildings provide approximately 405,709 square feet of net leasable retail sales and storage space (97% of which is currently leased) and approximately 18,590 square feet of net leasable general office space (99% of which is currently leased). Approximately 24% of the general office space is occupied by the Registrant's real estate operations. The fifteenth building is an eight-story medical office building which provides approximately 76,379 square feet of net leasable medical office space (44% of which is currently leased). Due to increased operating costs and related business considerations, the Registrant intends to close the Medical Building in January 2002. All tenant leases in the Medical Building shall have expired prior to such date. The Registrant has not decided as to the future use of the area upon which the Medical Building is located. I - 22 In September, 2001, the Registrant purchased one of its long-time Utica Square Shopping Center tenants, Miss Jackson's. Miss Jackson's is a retailer of fine women's clothing, accessories and gifts. The purchase price was $4,500,000. At the end of the 2001 fiscal year the Registrant owned 11 of a total of 73 units in The Yorktown, a 16-story luxury residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to Utica Square Shopping Center. Ten of the Registrant's units are currently leased. The Registrant owns an eight-story office building located diagonally across the street from Utica Square Shopping Center, containing approximately 87,000 square feet of net leasable general office space. This building houses the Registrant's principal executive offices. Approximately 11% of this building was leased to a third party during fiscal 2001. However, such third party's lease was not renewed and it vacated the leased premises in November of 2001. The vacated space will be used as general office space by Registrant. Registrant leases approximately 29,000 square feet of office space in Tulsa for Registrant's oil and gas division. The Registrant also owns and leases multi-tenant warehouse space. Three warehouses known as Space Center, each containing approximately 165,000 square feet of net leasable space, are situated in the southeast part of Tulsa at the intersection of two major limited-access highways. Present occupancy is 100%. The Registrant also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses. Registrant owns approximately 253.5 acres in Southpark consisting of approximately 240.5 acres of undeveloped real estate and approximately 13 acres of multi-tenant warehouse area. The warehouse area is known as Space Center East and consists of two warehouses, one containing I - 23 approximately 90,000 square feet and the other containing approximately 112,500 square feet. Occupancy has decreased from 100% to 93%. The Registrant believes that a high quality office park, with peripheral commercial, office/warehouse, and hotel sites, is the best development use for the remaining land. However, no development plans are currently pending. Registrant is a party to a condemnation proceeding initiated during fiscal 2000 by the Oklahoma Department of Transportation ("ODOT") which seeks to acquire approximately 15.14 acres of undeveloped real property adjacent to a major expressway in Southpark. In this proceeding, court appointed appraisers estimated the value of this tract to equal $2,800,000. ODOT, in January of 2001, was required to pay Registrant this amount, but continues to litigate the fair market value of this tract. If ODOT was successful at trial, Registrant would be required to reimburse up to $750,000 of such proceeds. It is expected that this matter will be concluded during calendar 2002. The Registrant also owns a five-building complex called Tandem Business Park. The project is located adjacent to and east of the Space Center East facility and contains approximately six acres, with approximately 88,084 square feet of office/warehouse space. Occupancy has decreased from 100% to 94% during fiscal 2001. The Registrant also owns a twelve-building complex, consisting of approximately 204,600 square feet of office/warehouse space, called Tulsa Business Park. The project is located south of the Space Center facility, separated by a city street, and contains approximately 12 acres. During fiscal 2001, occupancy has remained steady at 93%. However, on October 1, 2001, Registrant added a new tenant and increased total occupancy to 96%. The Registrant also owns two service center properties located adjacent to arterial streets in south central Tulsa. The first, called Maxim Center, consists of one office/warehouse building containing approximately 40,800 square feet and located on approximately 2.5 acres. During fiscal 2001, occupancy has decreased from 94% to 79%. On October 1, 2001, Registrant added one I - 24 new tenant bringing the occupancy to 94%. The second, called Maxim Place, consists of one office/warehouse building containing approximately 33,750 square feet and located on approximately 2.25 acres. During fiscal 2000, this property was 100% occupied by one tenant. During fiscal 2001, this tenant significantly reduced the size of its operation with such property presently being 17% occupied. Competition The Registrant has numerous competitors in the multi-tenant leasing business. The size and financial capacity of these competitors range from one property sole proprietors to large international corporations. The primary competitive factors include price, location and configuration of space. Registrant's competitive position is enhanced by the location of its properties, its financial capability and the long-term ownership of its properties. However, many competitors have financial resources greater than Registrant and have more contemporary facilities. FINANCIAL Information relating to Revenue and Operating Profit by Business Segments may be found on pages 9 and 31 through 32 of the Registrant's Annual Report to Shareholders for fiscal 2001, which is incorporated herein by reference. EMPLOYEES The Registrant had 3,043 employees within the United States (11 of which were part-time employees) and 1,202 employees in international operations as of September 30, 2001. I - 25 Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning the Registrant's domestic drilling rigs as of September 30, 2001:
Rig Registrant's Optimum Working Present Designation Classification Depth in Feet Location ----------- -------------- --------------- -------- 158 Medium Depth 10,000 Wyoming 110 Medium Depth 12,000 Oklahoma 156 Medium Depth 12,000 Texas 159 Medium Depth 12,000 Wyoming 141 Medium Depth 14,000 Texas 142 Medium Depth 14,000 Texas 143 Medium Depth 14,000 Texas 145 Medium Depth 14,000 Texas 155 Medium Depth 14,000 Texas 96 Medium Depth 16,000 Oklahoma 118 Medium Depth 16,000 Texas 119 Medium Depth 16,000 Texas 120 Medium Depth 16,000 Texas 146 Medium Depth 16,000 Texas 147 Medium Depth 16,000 Texas 154 Medium Depth 16,000 Wyoming 162 Medium Depth 16,000 Texas 164 Medium Depth 16,000 Texas 165 Medium Depth 16,000 Texas 166 Medium Depth 16,000 Texas 167 Medium Depth 16,000 Oklahoma 168 Medium Depth 16,000 Texas 169 Medium Depth 16,000 Texas 108 Medium Depth 18,000 Gulf of Mexico 178 Medium Depth 18,000 Texas 179 Medium Depth 18,000 Wyoming 180 Medium Depth 18,000 Wyoming 181 Medium Depth 18,000 Texas 182 Medium Depth 18,000 Texas 183 Medium Depth 18,000 Texas 184 Medium Depth 18,000 Texas 79 Deep 20,000 Louisiana 80 Deep 20,000 Oklahoma 89 Deep 20,000 Texas
I - 26
Rig Registrant's Optimum Working Present Designation Classification Depth in Feet Location ----------- -------------- --------------- -------- 91 Deep 20,000 Gulf of Mexico 92 Deep 20,000 Oklahoma 94 Deep 20,000 Texas 98 Deep 20,000 Oklahoma 122 Deep 20,000 Texas 203 Deep 20,000 Gulf of Mexico 97 Deep 26,000 Texas 99 Deep 26,000 Texas 137 Deep 26,000 Texas 149 Deep 26,000 Texas 170 Deep (Heli Rig) 26,000 Texas 72 Very Deep 30,000 Mississippi 73 Very Deep 30,000 Texas 100 Very Deep 30,000 Gulf of Mexico 105 Very Deep 30,000 Gulf of Mexico 106 Very Deep 30,000 Gulf of Mexico 107 Very Deep 30,000 Gulf of Mexico 134 Very Deep 30,000 Texas 136 Very Deep 30,000 Louisiana 157 Very Deep 30,000 Texas 161 Very Deep 30,000 Louisiana 163 Very Deep 30,000 Louisiana 201 Very Deep 30,000 Gulf of Mexico 202 Very Deep 30,000 Gulf of Mexico 204 Very Deep 30,000 Gulf of Mexico
The following table sets forth information with respect to the utilization of the Registrant's domestic drilling rigs for the periods indicated:
Years ended September 30, ------------------------- 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- Number of rigs owned at end of period 38 46 50 48 59 Average rig utilization rate during period (1) 88% 95% 75% 87% 97%
(1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. I - 27 The following table sets forth certain information concerning the Registrant's international drilling rigs as of September 30, 2001:
Rig Registrant's Optimum Working Present Designation Classification Depth in Feet Location ----------- -------------- ------------- -------- 14 Workover/drilling 6,000 Venezuela 19 Workover/drilling 6,000 Venezuela 20 Workover/drilling 6,000 Venezuela 140 Medium Depth 10,000 Venezuela 171 Medium Depth 16,000 Bolivia 172 Medium Depth 16,000 Bolivia 22 Medium Depth (Heli Rig) 18,000 Ecuador 23 Medium Depth (Heli Rig) 18,000 Ecuador 132 Medium Depth 18,000 Ecuador 176 Medium Depth 18,000 Ecuador 121 Deep 20,000 Ecuador 173 Deep 20,000 Bolivia 117 Deep 26,000 Ecuador 123 Deep 26,000 Bolivia 138 Deep 26,000 Ecuador 148 Deep 26,000 Venezuela 160 Deep 26,000 Venezuela 190* Deep 26,000 Texas 191* Deep 26,000 Texas 192* Deep 26,000 Texas 113 Very Deep 30,000 Venezuela 115 Very Deep 30,000 Venezuela 116 Very Deep 30,000 Venezuela 125* Very Deep 30,000 Texas 127 Very Deep 30,000 Venezuela 128 Very Deep 30,000 Venezuela 129 Very Deep 30,000 Venezuela 133 Very Deep 30,000 Colombia 135 Very Deep 30,000 Colombia 150 Very Deep 30,000 Venezuela 151 Very Deep 30,000 Bolivia 152 Very Deep 30,000 Colombia 153 Very Deep 30,000 Venezuela 174 Very Deep 30,000 Argentina 175 Very Deep 30,000 Bolivia 177 Very Deep 30,000 Argentina 139* Super Deep 30,000+ Texas
I - 28 *Rigs returned to the United States for major modifications and upgrades. The following table sets forth information with respect to the utilization of the Registrant's international drilling rigs for the periods indicated:
Years ended September 30, ------------------------- 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- Number of rigs owned at end of period 39 44 39 40 37 Average rig utilization rate during period (1)(2) 91% 88% 53% 47% 56%
(1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. (2) Does not include rigs returned to United States for major modifications and upgrades. OIL AND GAS DIVISION All of the Registrant's oil and gas operations and holdings are located within the continental United States. Crude Oil Sales The Registrant's net sales of crude oil and condensate for the fiscal years 1999 through 2001 are shown below:
Average Sales Average Lifting Year Net Barrels Price per Barrel Cost per Barrel ---- ----------- ---------------- --------------- 1999 649,370 $14.60 $7.02 2000 880,304 $27.95 $6.06 2001 818,356 $27.88 $7.76
I - 29 Natural Gas Sales The Registrant's net sales of natural and casinghead gas for the three fiscal years 1999 through 2001 are as follows:
Average Sales Average Lifting Year Net MCF Price per MCF Cost per MCF ---- ------------ ------------- --------------- 1999 44,240,332 $1.83 $0.3300 2000 46,922,752 $2.79 $0.3704 2001 42,386,796 $4.55 $0.6019
Following is a summary of the net wells drilled by the Registrant for the fiscal years ended September 30, 1999, 2000, and 2001:
Exploratory Wells Development Wells ----------------- ----------------- 1999 2000 2001 1999 2000 2001 ---- ---- ---- ---- ---- ---- Productive 2.917 9.735 9.0382 13.846 23.862 43.4622 Dry 2.615 5.7017 9.9618 4.502 3.403 7.0031
On September 30, 2001, the Registrant was in the process of drilling or completing eight gross or 4.6342 net wells. I - 30 Acreage Holdings The Registrant's holdings of acreage under oil and gas leases, as of September 30, 2001, were as follows:
Developed Acreage Undeveloped Acreage ----------------- ------------------- Gross Net Gross Net ----- --- ----- --- Arkansas 3,068.23 1,725.11 -0- -0- Colorado -0- -0- 320.00 160.00 Kansas 119,633.07 84,079.86 13,081.82 12,752.60 Louisiana 3,481.48 1,589.14 80,020.27 23,166.46 Michigan -0- -0- 4,123.64 4,123.64 Montana 1,997.19 377.99 2,708.95 969.73 Nebraska 480.00 168.00 -0- -0- Nevada -0- -0- 4,864.04 4,864.04 New Mexico 760.00 96.63 121.88 40.22 North Dakota 200.00 11.52 -0- -0- Oklahoma 123,559.86 49,647.24 27,138.98 16,664.45 Texas 87,692.92 43,885.47 190,421.95 87,554.14 Wyoming -0- -0- 440.00 105.59 ---------- ---------- ---------- ---------- Total 340,872.75 181,580.96 323,241.53 150,400.87
Acreage is held under leases which expire in the absence of production at the end of a prescribed primary term, and is, therefore, subject to fluctuation from year to year as new leases are acquired, old leases expire, and other leases are allowed to terminate by failure to pay annual delay rentals. As shown in the above table, the Registrant has a significant portion of its undeveloped acreage in Texas, with nine major project areas accounting for 40,517 net acres. The average minimum remaining term of leases in these nine project areas is approximately 16 months. I - 31 Productive Wells The Registrant's total gross and net productive wells as of September 30, 2001, were as follows:
Oil Wells Gas Wells --------- --------- Gross Net Gross Net 3,438 168 1,026 493
Additional information required by this item with respect to the Registrant's oil and gas operations may be found on pages I-11 through I-22 of Item 1. BUSINESS, and pages 23 through 34 of the Registrant's Annual Report to Shareholders for fiscal 2001, "Notes to Consolidated Financial Statements" and "Note 15 Supplementary Financial Information for Oil and Gas Producing Activities." Estimates of oil and gas reserves, future net revenues, and present value of future net revenues were prepared by Netherland, Sewell & Associates, Inc., 4950 Three Allen Center, 333 Clay Street, Houston, Texas 77002. Total oil and gas reserve estimates do not differ by more than 5% from the total reserve estimates filed with any other federal authority or agency. REAL ESTATE OPERATIONS See Item 1. BUSINESS, pages I-22 through I-25. I - 32 STOCK As of December 14, 2001: The Registrant owned 312,546 shares of the common stock of SUNOCO, Inc. and 150,000 shares of Kerr McGee Corporation. The Registrant owned 3,000,000 shares of the common stock of Atwood Oceanics, Inc., a Houston, Texas based company engaged in offshore contract drilling. The Registrant owns approximately 22% of Atwood. The Registrant owned 1,480,000 shares of the common stock of Schlumberger, Ltd. The Registrant owned 240,000 shares of the common stock of Phillips Petroleum Company, Inc. The Registrant owned 150,000 shares of the common stock of Occidental Petroleum Corporation, Inc. The Registrant owned 175,000 shares of the common stock of Banc One Corporation. The Registrant owned 450,000 shares of the common stock of ONEOK Inc. The Registrant owned 286,528 shares of the common stock of Transocean Sedco Forex, Inc., which it received in a merger between Transocean Offshore and the contract drilling division of Schlumberger. The Registrant owned 168,350 shares of the common stock of Protein Design Labs, Inc. The Registrant also owned lesser holdings in several other publicly traded corporations. Item 3. LEGAL PROCEEDINGS There are no material legal proceedings pending against the Registrant or its subsidiaries. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. I - 33 EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth the names and ages of the Registrant's executive officers, together with all positions and offices held with the Registrant by such executive officers. Officers are elected to serve until the meeting of the Board of Directors following the next Annual Meeting of Stockholders and until their successors have been elected and have qualified or until their earlier resignation or removal. W. H. Helmerich, III, 78 Director since 1949; Chairman of the Board Chairman of the Board since 1960 Hans Helmerich, 43 Director since 1987; President and Chief President Executive Officer since 1989 George S. Dotson, 60 Director since 1990; Vice President, Vice President Drilling since 1977 and President and Chief Operating Officer of Helmerich & Payne International Drilling Co. since 1977 Douglas E. Fears, 52 Vice President, Finance, since 1988 Vice President Steven R. Mackey, 50 Secretary since 1990; Vice President and Vice President and General Counsel since 1988 Secretary Steven R. Shaw, 50 Vice President, Production, since 1985; Vice President Vice President, Exploration and Production since 1996 Gordon K. Helm, 48 Chief Accounting Officer of the Registrant; Controller Controller since December 10, 1993
I - 34 PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The principal market on which the Registrant's common stock is traded is the New York Stock Exchange. The high and low sale prices per share for the common stock for each quarterly period during the past two fiscal years as reported in the NYSE - Composite Transaction quotations follow:
2000 2001 ------------------ ----------------- Quarter High Low High Low ------- ---- --- ---- --- First 27.44 19.13 44.19 28.94 Second 31.00 20.00 58.51 39.63 Third 37.75 29.06 51.23 30.82 Fourth 38.31 30.06 32.77 23.74
The Registrant paid quarterly cash dividends during the past two years as shown in the following table:
Paid per Share Total Payment ------------------ ---------------------- Fiscal Fiscal ------------------ ---------------------- Quarter 2000 2001 2000 2001 ------- ---- ---- ---- ---- First $0.070 $0.075 $3,474,612 $3,748,896 Second 0.070 0.075 3,475,623 3,776,612 Third 0.070 0.075 3,484,189 3,796,489 Fourth 0.075 0.075 3,740,863 3,765,488
The Registrant paid a cash dividend of $.075 per share on December 3, 2001, to shareholders of record on November 15, 2001. Payment of future dividends will depend on earnings and other factors. As of December 14, 2001, there were 1,090 record holders of the Registrant's common stock as listed by the transfer agent's records. II-1 Item 6. SELECTED FINANCIAL DATA
Five-year Summary of Selected Financial Data ------------------------------------------------------------- 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- (in thousands) Sales, operating, and other revenues $ 517,859 $636,640 $ 564,319 $ 631,095 $ 826,854 Income from con- tinuing operations 84,186 101,154 42,788 82,300 144,254 Income from con- tinuing operations per common share: Basic 1.69 2.03 0.87 1.66 2.88 Diluted 1.67 2.00 0.86 1.64 2.84 Total assets 1,033,595 1,090,430 1,109,699 1,259,492 1,364,507 Long-term debt -0- 50,000 50,000 50,000 50,000 Cash dividends declared per common share 0.26 0.275 0.28 0.285 0.30
Item 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Information required by this item may be found on pages 10 through 17, Management's Discussion & Analysis of Results of Operations and Financial Condition, in the Registrant's Annual Report to Shareholders for fiscal 2001, which is incorporated herein by reference. II-2 Item 7(a). QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found on the following pages of Management's Discussion & Analysis of Results of Operations and Financial Condition and in Notes to Consolidated Financial Statements, in the Registrant's Annual Report to Shareholders for fiscal 2001, which is incorporated herein by reference:
Market Risk Page ----------- ---- o Foreign Currency Exchange Rate Risk 13-14, 23 o Commodity Price Risk 14-15, 29 o Interest Rate Risk 17, 24 o Equity Price Risk 17, 23
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found on pages 18 through 34 in the Registrant's Annual Report to Shareholders for fiscal 2001, which is incorporated herein by reference. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. II-3 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required under this item with respect to Directors and with respect to delinquent filers pursuant to Item 405 of Regulation S-K is incorporated by reference from the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2002, to be filed with the Commission not later than 120 days after September 30, 2001. See page I-34 for information covering the Registrant's Executive Officers. Item 11. EXECUTIVE COMPENSATION This information is incorporated by reference from the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2002, to be filed with the Commission not later than 120 days after September 30, 2001. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT This information is incorporated by reference from the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2002, to be filed with the Commission not later than 120 days after September 30, 2001. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS This information is incorporated by reference from the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2002, to be filed with the Commission not later than 120 days after September 30, 2001. III - 1 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Document List 1. The financial statements called for by Item 8 are incorporated herein by reference from the Registrant's Annual Report to Shareholders for fiscal 2001. 2. Exhibits required by Item 601 of Regulation S-K: Exhibit Number: 3.1 Restated Certificate of Incorporation and Amendment to Restated Certificate of Incorporation of the Registrant are incorporated herein by reference to Exhibit 3.1 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. 3.2 By-Laws of the Registrant are incorporated herein by reference to Exhibit 3.2 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. 4.1 Rights Agreement dated as of January 8, 1996, between the Registrant and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Registrant's Form 8-A, dated January 18, 1996, SEC File No. 001-04221. * 10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Registrant effective January 1, 1990, as amended is incorporated herein by reference to Exhibit 10.3 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. * 10.2 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.6 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. * 10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is incorporated herein by reference to Exhibit 10.7 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001- 04221. - ----------------------- * Compensatory Plan or Arrangement. IV-1 * 10.4 Form of Nonqualified Stock Option Agreement for the 1990 Stock Option Plan is incorporated by reference to Exhibit 99.2 to the Registrant's Registration Statement No. 33-55239 on Form S-8, dated August 26, 1994. * 10.5 Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1999, SEC File No. 001-04221. * 10.6 Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to Registrant's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. * 10.7 Form of Nonqualified Stock Option Agreement for Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to Registrant's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. * 10.8 Form of Restricted Stock Agreement for Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1997, SEC File No. 001-04221. * 10.9 Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Registrant's Registration Statement No. 333- 63124 on Form S-8 dated June 15, 2001. * 10.10 Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to Registrant's Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. 13. The Registrant's Annual Report to Shareholders for fiscal 2001. 21. Subsidiaries of the Registrant. - ----------------------- * Compensatory Plan or Arrangement. IV-2 23.1 Consent of Independent Auditors. (b) Report on Form 8-K None. - ----------------------- * Compensatory Plan or Arrangement. IV-3 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized: HELMERICH & PAYNE, INC. By Hans Helmerich ---------------------------- Hans Helmerich, President (Chief Executive Officer) Date: December 27, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: By William L. Armstrong By Glenn A. Cox ----------------------------------- ----------------------------------- William L. Armstrong, Director Glenn A. Cox, Director Date: December 27, 2001 Date: December 27, 2001 By George S. Dotson By Hans Helmerich ----------------------------------- ----------------------------------- George S. Dotson, Director Hans Helmerich, Director and CEO Date: December 27, 2001 Date: December 27, 2001 By W. H. Helmerich, III By L. F. Rooney, III ----------------------------------- ----------------------------------- W. H. Helmerich, III, Director L. F. Rooney, III, Director Date: December 27, 2001 Date: December 27, 2001 By Edward B. Rust, Jr. By George A. Schaefer ----------------------------------- ----------------------------------- Edward B. Rust, Jr., Director George A. Schaefer, Director Date: December 27, 2001 Date: December 27, 2001 By John D. Zeglis By Douglas E. Fears ----------------------------------- ----------------------------------- John D. Zeglis, Director Douglas E. Fears Date: December 27, 2001 (Principal Financial Officer) Date: December 27, 2001 By Gordon K. Helm ----------------------------------- Gordon K. Helm, Controller (Principal Accounting Officer) Date: December 27, 2001
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - -------- ----------- 3.1 Restated Certificate of Incorporation and Amendment to Restated Certificate of Incorporation of the Registrant are incorporated herein by reference to Exhibit 3.1 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. 3.2 By-Laws of the Registrant are incorporated herein by reference to Exhibit 3.2 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. 4.1 Rights Agreement dated as of January 8, 1996, between the Registrant and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Registrant's Form 8-A, dated January 18, 1996, SEC File No. 001-04221. * 10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Registrant effective January 1, 1990, as amended is incorporated herein by reference to Exhibit 10.3 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. * 10.2 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.6 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. * 10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is incorporated herein by reference to Exhibit 10.7 of the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. * 10.4 Form of Nonqualified Stock Option Agreement for the 1990 Stock Option Plan is incorporated by reference to Exhibit 99.2 to the Registrant's Registration Statement No. 33-55239 on Form S-8, dated August 26, 1994. * 10.5 Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1999, SEC File No. 001-04221. * 10.6 Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to Registrant's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. * 10.7 Form of Nonqualified Stock Option Agreement for Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to Registrant's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. * 10.8 Form of Restricted Stock Agreement for Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Registrant's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1997, SEC File No. 001-04221. * 10.9 Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Registrant's Registration Statement No. 333- 63124 on Form S-8 dated June 15, 2001. * 10.10 Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to Registrant's Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. 13. The Registrant's Annual Report to Shareholders for fiscal 2001. 21. Subsidiaries of the Registrant. 23.1 Consent of Independent Auditors.
- ----------------------- * Compensatory Plan or Arrangement. EX-13 3 d93048ex13.txt ANNUAL REPORT TO SHAREHOLDERS FOR FISCAL 2001 EXHIBIT 13 =============================================== HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2001 =============================================== REVENUE BREAKDOWN FOR 2001 [PIE CHART] CONTRACT DRILLING: International 19% Domestic 40% OIL AND GAS: Natural Gas Marketing 12% Exploration & Production 26% Real Estate 1% Investments and Other Income 2%
FINANCIAL HIGHLIGHTS ------------------------------------------------------------------- Years Ended September 30, 2001 2000 ------------------------- -------------- ----------------- Revenues $ 826,854,000 $ 631,095,000 Net Income $ 144,254,000 $ 82,300,000 Diluted Earnings Per Share $ 2.84 $ 1.64 Dividends Paid Per Share $ .30 $ .285 Capital Expenditures $ 274,670,000 $ 131,932,000 Total Assets $1,364,507,000 $ 1,259,492,000
================================================================================ PRESIDENT'S LETTER ================================================================================ To the Co-owners of Helmerich & Payne, Inc. Sometimes risk factors are difficult to identify, much less quantify. Unthinkable risks confronted each of us and our families in the aftermath of the terrorist attacks on the World Trade Center and Pentagon. Dinner table conversations at home and discussions at work contemplated possible threats of anthrax exposure, bioterror, and even nuclear "dirty bomb" strikes on civilians. Today we are a nation at war, facing a real and present danger to our basic freedoms and liberty. We are also a nation united and determined. A renewed patriotic spirit has raised a standard against the evil that struck at our core values. We have witnessed acts of untold heroism and sacrifice, along with a flood of prayers and support from friends of freedom around the globe. We have been inspired by the leadership of President Bush: "The course of this conflict is not known, yet its outcome is certain. Freedom and fear, justice and cruelty have always been at war and we know that God is not neutral between them. The advance of human freedom now depends on us. We will rally the world to this cause by our efforts, by our courage. We will not tire, we will not falter, and we will not fail." 2 The President has urged all Americans to take up the fight, in part, by leading our lives. That is what your Company intends to do. Each of our employees plays a proud part in an industry vital to our country's energy security. Remarkably, energy prices are falling at the end of 2001, even in the face of the current geopolitical situation in the Middle East. Will a "smoking gun" surface to further implicate Iraq in terrorist sponsorship? Will a bloody and volatile Palestinian-Israeli conflict deteriorate further? How should markets price the possible risk of a far-reaching supply disruption? We're confident the market will sort it all out. That time-tested dynamic of free markets is one of the many enduring principles worth fighting for and defending. All the while, your Company will stand prepared and financially fit for the challenges and opportunities ahead. Sincerely, /s/ HANS HELMERICH Hans Helmerich December 14, 2001 President 3 ================================================================================ DRILLING HELMERICH & PAYNE INTERNATIONAL DRILLING CO. ================================================================================ SUMMARY Both oil and natural gas prices increased substantially at the beginning of the year, resulting in higher demand for land rigs in the United States. Industry census data produced by Reed-Hycalog indicates that 93 percent of all U.S. land rigs were active during 2001, a level of activity not achieved since the early 1980s. The resulting impact of this environment on the Company's 2001 financial performance was significant. Contract drilling revenues increased 39 percent, and earnings before interest, taxes, depreciation, and amortization (EBITDA) increased by over 50 percent, driven primarily by increased activity in the U.S. land market.
FIVE-YEAR OPERATING SUMMARY - ----------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 -------- -------- -------- -------- -------- (Dollar figures in thousands) UNITED STATES Revenues ........... $332,399 $214,531 $213,647 $177,059 $140,294 EBITDA ............. $133,968 $ 71,163 $ 61,498 $ 60,053 $ 44,066 Operating Profit ... $107,691 $ 35,808 $ 30,154 $ 35,817 $ 24,437 Activity Days ...... 18,656 15,083 12,509 14,237 12,872 Rig Utilization .... 97% 87% 75% 95% 88% INTERNATIONAL Revenues ........... $154,890 $136,549 $182,987 $253,072 $176,651 EBITDA ............. $ 47,313 $ 47,853 $ 66,075 $ 82,650 $ 69,621 Operating Profit ... $ 28,475 $ 9,753 $ 29,845 $ 50,834 $ 43,118 Activity Days ...... 7,283 7,067 8,442 12,832 12,253 Rig Utilization .... 56% 47% 53% 88% 91%
At the close of fiscal 2001, Helmerich & Payne International Drilling Co. owned ten offshore platform rigs located in the Gulf of Mexico, and 81 land rigs located in the United States (49), Venezuela (14), Ecuador (7), Bolivia (6), Colombia (3), and Argentina (2). The Company also had five international land rigs undergoing major upgrades in the U.S., as well as five land rigs and two offshore platform rigs at various stages of new construction at year-end. 4 Additionally, the Company operates four management contracts on customer-owned platform rigs, three offshore California and one offshore Equatorial Guinea, West Africa. UNITED STATES OPERATIONS Rig utilization averaged 97 and 98 percent, respectively, for land and offshore platform rigs during the year. The Company worked an average of 41 land rigs and ten offshore platform rigs for the whole year, up from 32 land and nine offshore platform rigs in 2000. A total of 11 rigs were added to the land fleet in 2001, seven new FlexRigs(TM), one reconditioned medium depth rig, and three deep rigs that were transferred from international operations. The Company plans to complete the construction of 20 FlexRigs during 2002, which will be available for work in the U.S. or international markets. The highly mobile FlexRig, named for its flexible drilling range of 8,000 to 18,000 feet, offers significant drilling efficiencies through improved technology, including disc-brakes, block control system, and the Company's patented round mud tank system. The FlexRig design has reduced the average moving time by more than one-half of that for a conventional 1500 horsepower rig. The FlexRig design includes many health, safety, and environmental (HSE) improvements and features reducing HSE hazards. These include noise abatement, enhanced anti-fall protection, and an integrated fluid containment system around the rig floor. During 2001, the Company received commitments to build and operate two new self-moving platform rigs in the Gulf of Mexico, one each from Shell Exploration & Production Co. and BP. These rigs are scheduled to commence operations in the third quarter of 2002. (TM) FlexRig is a trademark of Helmerich & Payne International Drilling Co. 5 INTERNATIONAL OPERATIONS Rig utilization averaged 56 percent in 2001, compared with 47 percent in 2000, primarily because the Company moved eight rigs to the U.S. for drilling opportunities or refurbishment during 2001. Revenues increased 13 percent over last year, but EBITDA decreased slightly as improvements in Venezuela, Equatorial Guinea, Ecuador, and Argentina were offset by declines in Colombia and Bolivia. Increased operating profit was primarily the result of reduced depreciation expense caused by rig transfers from international to domestic operations, as well as a change in the estimated useful life of drilling equipment, increasing it from ten to 15 years. OUTLOOK The Company has lowered its expectations for drilling activity in the coming year because of the precipitous drop in both oil and natural gas prices caused by reduced economic activity and mild weather in the U.S. Because the present downturn does not appear to be due to excessive supplies, the Company anticipates that it will be short-lived, improving as energy demand rises in response to U.S. and world economic recovery. This is the second volatile drilling cycle in four years and, with each downturn, the industry loses experienced employees and momentum on capital projects, many of which require long lead times to bring to fruition. The inevitable upturn in the cycle is likely to become even more pronounced, stretching the already thin human, technological, and financial resources of the industry. The Company has focused its investment efforts on delivering the latest in equipment and technology to the field and in training our people to operate safely and effectively. Our primary goal remains to deliver high quality equipment and services that will add measurable value to a customer's drilling operation. 6 ================================================================================ EXPLORATION & PRODUCTION HELMERICH & PAYNE, INC. ================================================================================ SUMMARY Helmerich & Payne, Inc. explores for and produces oil and natural gas primarily in Kansas, Louisiana, Oklahoma, and Texas. The Company also provides natural gas marketing services through its wholly owned subsidiary, Helmerich & Payne Energy Services, Inc. A substantial increase in the price of natural gas produced record financial results for the Exploration and Production segment in 2001. Revenues and operating profit grew 38 percent and 44 percent, respectively, over 2000 levels. Helmerich & Payne Energy Services, Inc.'s revenues increased 24 percent in 2001, although operating profit remained flat for the year. Oil production declined seven percent to average 2,242 barrels per day in 2001, while prices remained flat at $27.88 per barrel compared with $27.95 per barrel in 2000. Natural gas production also declined to 116,128 thousand cubic feet (Mcf) per day, compared with 128,204 Mcf per day in 2000. Natural gas prices increased 63 percent to average $4.55 per Mcf in 2001, compared with $2.79 per Mcf in 2000.
FIVE-YEAR OPERATING SUMMARY - ---------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- (Revenues and operating profit in thousands) Revenues............................... $ 217,194 $ 157,583 $ 95,953 $ 98,696 $ 111,512 Operating Profit....................... $ 95,579 $ 66,604 $ 11,245 $ 28,088 $ 55,191 Average Oil Price per barrel ......... $ 27.88 $ 27.95 $ 14.60 $ 14.74 $ 20.77 Oil Production (barrels) ............. 818,356 880,304 649,370 701,180 985,633 Proved Oil Reserves (barrels) ........ 5,931,595 6,305,137 4,833,898 4,761,313 5,805,386 Average Natural Gas Prices per Mcf ... $ 4.55 $ 2.79 $ 1.83 $ 2.04 $ 2.24 Natural Gas Production (Mcf) ......... 42,386,796 46,922,752 44,240,332 42,862,300 40,463,374 Proved Natural Gas Reserves (Bcf) .... 216.3 262.5 239.6 251.6 263.2 Gross Wells Completed ................ 123.0 81.0 49.0 62.0 100.0 Net Wells Completed .................. 69.5 42.7 23.9 35.7 49.3 Net Dry Holes ........................ 17.0 9.1 7.1 4.2 9.6
7 EXPLORATION RESULTS Even though the Company had a record financial performance, it was a disappointing year for the exploration effort. Proved reserves declined from 300 billion cubic feet equivalent (Bcfe) to 252 Bcfe during 2001. Almost half of this decline was the result of the lower natural gas price used in the reserve calculation, which was $1.90 per Mcf in 2001, compared with $5.13 per Mcf in 2000. The Company participated in 123 (69.5 net) wells in 2001, 29 (17 net) of which were dry holes. Given the high natural gas prices, additional emphasis was placed on developing proved undeveloped reserves during the year. Forty-seven gross wells were drilled for this purpose in 2001. The remaining wells included 40 (19 net) wildcat wells, five of which exposed the Company to over 250 Bcfe in net potential reserve additions. OUTLOOK Given that oil and gas prices have declined substantially, the Company plans to be highly selective with regard to drilling prospects in 2002, and will reduce capital expenditures by as much as half of what they were in 2001. With the assistance of the investment bank of Petrie Parkman & Co., the Company is continuing to explore strategic alternatives for the Oil and Gas Division. These alternatives include combining the Company's oil and gas operations with another of similar size to form a separate, stand-alone exploration and production company. The Company engaged in discussions with a number of companies during the past year and plans to continue these efforts into 2002. 8 REVENUES AND OPERATING PROFIT BY BUSINESS SEGMENTS ================================================================================ HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999 - --------------------------------------------------------------- -------- -------- -------- (in thousands) SALES AND OTHER REVENUES: Contract Drilling - Domestic.............................. $332,399 $214,531 $213,647 Contract Drilling - International......................... 154,890 136,549 182,987 -------- -------- -------- Total Contract Drilling................................ 487,289 351,080 396,634 -------- -------- -------- Exploration and Production................................ 217,194 157,583 95,953 Natural Gas Marketing..................................... 100,111 80,907 55,259 -------- -------- -------- Total Oil and Gas Operations........................... 317,305 238,490 151,212 -------- -------- -------- Real Estate .............................................. 11,018 8,999 8,671 Other..................................................... 11,242 32,526 7,802 -------- -------- -------- Total Revenues................................................. $826,854 $631,095 $564,319 ======== ======== ======== OPERATING PROFIT: Contract Drilling - Domestic.............................. $107,691 $ 35,808 $ 30,154 Contract Drilling - International......................... 28,475 9,753 29,845 -------- -------- -------- Total Contract Drilling................................ 136,166 45,561 59,999 -------- -------- -------- Exploration and Production................................ 95,579 66,604 11,245 Natural Gas Marketing..................................... 5,254 5,271 4,418 -------- -------- -------- Total Oil and Gas Operations........................... 100,833 71,875 15,663 -------- -------- -------- Real Estate............................................... 6,315 5,346 5,338 -------- -------- -------- Total Operating Profit................................. 243,314 122,782 81,000 -------- -------- -------- OTHER: Income from investments................................... 10,592 31,973 7,757 General and administrative expense........................ (15,415) (11,578) (14,198) Interest expense.......................................... 32 (3,076) (6,481) Corporate depreciation.................................... (2,043) (2,152) (1,565) Other corporate expense................................... (1,378) (1,186) (1,575) -------- -------- -------- Total Other............................................ (8,212) 13,981 (16,062) -------- -------- -------- INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES............................ $235,102 $136,763 $ 64,938 ======== ======== =========
Note: See Note 14 (pages 30, 31 and 32) for complete segment disclosure. 9 MANAGEMENT'S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ================================================================================ HELMERICH & PAYNE, INC. RISK FACTORS AND FORWARD-LOOKING STATEMENTS The following discussion should be read in conjunction with the consolidated financial statements and related notes included elsewhere herein. The Company's future operating results may be affected by various trends and factors, which are beyond the Company's control. These include, among other factors, fluctuations in oil and natural gas prices, expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, and uncertain business conditions that affect the Company's businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends. With the exception of historical information, the matters discussed in Management's Discussion & Analysis of Results of Operations and Financial Condition include forward-looking statements. These forward-looking statements are based on various assumptions. The Company cautions that, while it believes such assumptions to be reasonable and makes them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. The Company is including this cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. The factors identified in this cautionary statement are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company. RESULTS OF OPERATIONS All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Helmerich & Payne, Inc.'s net income for 2001 was $144,254,000 ($2.84 per share), compared with net income of $82,300,000 ($1.64 per share) in 2000, and $42,788,000 ($0.86 per share) in 1999. Included in the Company's net income, but not related to its operations, were after-tax gains from the sale of investment securities of $691,000 ($0.01 per share) in 2001, $8,152,000 ($0.16 per share) in 2000, and $1,562,000 ($0.03 per share) in 1999. In addition to income from security sales, the Company also recorded net income during 2000 of $6,637,000 ($0.13 per share) from gains relating to non-monetary dividends received. Also included in net income is the Company's portion of income from its 10 equity affiliates, which totaled $0.04 per share in 2001, $0.06 in 2000, and $0.07 in 1999. The Company's equity affiliates are Atwood Oceanics, Inc. and a 50-50 joint venture with Atwood called Atwood Oceanics West Tuna Pty. Ltd., which owns an offshore platform rig. Consolidated revenues were $826,854,000 in 2001, $631,095,000 in 2000, and $564,319,000 in 1999. The 31 percent increase from 2000 to 2001 was due to significant increases in revenues from all of the operating divisions. Revenues from investments decreased by $21,381,000. Contract Drilling Division revenues increased by 39 percent due to the strengthening of the U.S. land rig market. This resulted in higher utilization of the Company's rigs and higher dayrates. Oil and Gas Division revenues rose 33 percent over 2000 due primarily to higher oil and natural gas prices. The 12 percent increase in consolidated revenues from 1999 to 2000 was primarily due to higher oil and natural gas prices resulting in an increase of $87,278,000 in Oil and Gas Division revenues and increased investment revenues of $24,216,000. Partially offsetting these increases was a reduction of international contract drilling revenues of $46,438,000. Revenues from investments were $10,592,000 in 2001, $31,973,000 in 2000, and $7,757,000 in 1999. Included in revenues were pre-tax gains from the sale of investment securities of $1,189,000 in 2001, $13,295,000 in 2000, and $2,547,000 in 1999. Interest income from short-term investments increased in 2001 and 2000 because the Company's cash and cash equivalent balances increased in each of these years. Dividend income decreased in 2001, primarily because in 2000, the Company recognized $10,706,000 of non-monetary dividends when three Company investees spun-off subsidiaries to their shareholders. Costs and expenses in 2001 were $591,752,000, 72 percent of revenues, compared with 78 percent in 2000, and 88 percent in 1999. Operating costs, as a percentage of operating revenues, were 51 percent in 2001, 53 percent in 2000, and 60 percent in 1999. Operating costs, as a percentage of operating revenues, declined each of the last two years, primarily due to proportionately higher revenues. Effective October 1, 2000, the Company changed the estimated useful life of its drilling equipment from ten years to 15 years, resulting in lower annual depreciation expense of approximately $30 million in 2001. Excluding write-downs of producing properties, depreciation expense was $78,400,000 in 2001, $106,815,000 in 2000, and $99,108,000 in 1999. Producing property 11 write-downs totaled $8,909,000 in 2001, $4,036,000 in 2000, and $10,059,000 in 1999. General and administrative expenses increased by 33 percent from 2000 to 2001, to a total of $15,415,000, compared with $11,578,000 in 2000, and $14,198,000 in 1999. Expenses rose this past year due to costs associated with legal, accounting, and investment banking fees related to the potential spin-off of the Oil and Gas Division, settlements of lawsuits, higher pension expense accrual, and higher labor and bonus charges, compared with 2000. General and administrative expenses decreased in 2000, compared to 1999, due to the inclusion in 1999 of reduced allocations of charges to operations and unusually high expenses relating to corporate aircraft maintenance. Income taxes, as a percentage of pre-tax income, were 40 percent in 2001, 42 percent in 2000, and 40 percent in 1999. Interest expense for the Company was negative $32,000 in 2001, $3,076,000 in 2000, and $6,481,000 in 1999. Most of the expense reduction from 2000 to 2001 resulted from a reversal of interest expense previously accrued relating to an ad valorem tax dispute that was settled for less interest costs than accrued. The specific case was settled during 2001, resulting in a reversal of interest expense of $2,280,000 that had been accrued in 1999. Additionally, the Company reduced its overall debt position during the last half of 1999 and early 2000, resulting in less debt related interest expense booked in the last three years. CONTRACT DRILLING DIVISION revenues, which include both domestic and international segment revenues, increased 39 percent to $487,289,000 during 2001, from $351,080,000 in 2000. Revenues for 2000 were 11 percent lower than in 1999. Division operating profit of $136,166,000 was almost triple that of the $45,461,000 recorded in 2000. Operating profit for 2000 was 24 percent lower than in 1999. Domestic segment revenues were $332,399,000 in 2001, $214,531,000 in 2000, and $213,647,000 in 1999. Domestic segment operating profit was $107,691,000 in 2001, $35,808,000 in 2000, and $30,154,000 in 1999. Rig utilization for the U.S. land fleet was 97 percent in 2001, 85 percent in 2000, and 69 percent in 1999. Domestic platform rig utilization was 98 percent in 2001, 94 percent in 2000, and 95 percent in 1999. Both U.S. land rig and U.S. platform rig revenues increased in 2001 over 2000. Dayrates for U.S. land rigs and total operating days for the U.S. land rig segment increased dramatically during 2001. Operating profit for the 12 domestic operation improved dramatically from 2000 to 2001, mostly on the strength of average land rig dayrates, which improved more than 50 percent, and the resulting improvement in profit margins. The previously discussed change in the estimated useful life of drilling equipment increased domestic operating profit by approximately $15 million in 2001. U.S. platform rig dayrates did not improve, but total operating days helped boost revenues for the year. Improvements in revenues and operating profit from 1999 to 2000 were primarily the result of average U.S. land rig dayrates and profit margins moving up, while the platform business improved only slightly. During 1999, there were approximately $40 million of revenues recorded as a result of a rig construction project that was completed in early 2000. International segment revenues increased by 13 percent from 2000 to 2001, after falling by 25 percent from 1999 to 2000. International operating profit rose to $28,475,000 in 2001, from $9,753,000 in 2000. Operating profit for 1999 was $29,845,000. International rig utilization averaged 56 percent during 2001, 47 percent in 2000, and 53 percent in 1999. International operating profit improved during 2001, mainly due to lower depreciation expenses resulting from a change in the estimated useful life of the Company's drilling equipment, as previously discussed. The impact of the change added approximately $15 million to international operating profit in 2001. Revenues in Venezuela increased 24 percent during 2001, and the Company expects to see activity improve slightly in 2002. The Company's labor contract in Equatorial Guinea added $6,054,000 to international revenues in 2001. The decline in operating profit from 1999 to 2000 was primarily due to reduced activity in Colombia where the Company had previously employed ten rigs. Activity in Colombia continued to decline in 2000 and 2001, and currently, the Company has one rig working out of the three remaining in that country. Conversely, Ecuador's rig count has grown from three in 1999 to seven in 2001, and an eighth, newly refurbished rig will be shipped during the second quarter of 2002, to begin work under a one-year contract. The Company has international operations in several South American countries. With the exception of Venezuela, the Company believes that its exposure to currency valuation losses is minimal due to the fact that virtually all billings and payments are in U.S. dollars. In Venezuela, approximately 50 percent of the Company's billings are in U.S. dollars and 50 percent are in bolivars, the local currency. As a result, the Company is exposed to risks of currency devaluation in Venezuela because of the bolivar denominated receivables. During 2001, the Company experienced a loss of $796,000 due to devaluation of the bolivar, 13 compared with a $687,000 loss in 2000, and a $712,000 loss in 1999. The Company anticipates additional devaluation losses in Venezuela during 2002, but is unable to predict the extent of either the devaluation or its financial impact. Should Venezuela experience a 25 to 50 percent devaluation, Company losses could range from approximately $1,600,000 to $2,600,000. OIL AND GAS DIVISION operating results include those from its Exploration and Production segment, as depicted in the following table. The Natural Gas Marketing segment will be discussed separately.
Exploration & Production 2001 2000 1999 - ------------------------------------------ ------------ ------------ ------------ Revenues (in 000's) ...................... $ 217,194 $ 157,583 $ 95,953 Operating Profit (in 000's) .............. $ 95,579 $ 66,604 $ 11,245 Natural Gas Production (Mmcf per day) .... 116.1 128.2 121.2 Average Natural Gas Price (per Mcf) ...... $ 4.55 $ 2.79 $ 1.83 Crude Oil Production (barrels per day) ... 2,242 2,405 1,779 Average Crude Oil Price (per barrel) ..... $ 27.88 $ 27.95 $ 14.60
Exploration and Production segment revenues and operating profit increased significantly this year as average prices received for the Company's natural gas production rose dramatically. Average prices received for natural gas increased by 63 percent, while average crude oil prices remained flat, compared to 2000. Natural gas and crude oil production for the Company decreased by nine percent and seven percent, respectively. Increased exploration drilling resulted in dry hole and abandonment charges rising to $33.5 million in 2001, compared with $22.6 million in 2000, and $11.4 million in 1999. Revenues and operating profit for 2000 were up substantially from 1999 due to significant increases in both commodity price levels and Company production volumes for natural gas and crude oil. Average prices for natural gas increased by 52 percent and average crude oil prices increased by 91 percent from 1999 to 2000. In 2000, natural gas and crude oil production increased by six percent and 35 percent, respectively, over 1999 levels. Producing property impairment write-downs totaled $8,909,000 in 2001, $4,036,000 in 2000, and $10,059,000 in 1999. During 2002, the Company's Oil and Gas Division intends to decrease its capital spending over the previous year. However, dry hole, abandonment, and geophysical expenses are difficult to predict and will continue to impact operating profit for the coming year. Additionally, with a reduced capital spending budget, it is expected that the Company's production volumes for natural gas and crude oil will decline during the year. 14 The Company has retained the investment banking firm of Petrie Parkman & Co. to analyze, develop, and facilitate possible strategic options for the Oil and Gas Division. It is uncertain whether such a transaction will occur or, if so, when. The Company's Natural Gas Marketing segment, Helmerich & Payne Energy Services, Inc., (HPESI) derives most of its revenues from selling natural gas produced by other unaffiliated companies. Total Natural Gas Marketing segment revenues were $100,111,000 in 2001, $80,907,000 in 2000, and $55,259,000 in 1999. Operating profit was $5,254,000 in 2001, $5,271,000 in 2000, and $4,418,000 in 1999. The operating profit margin declined to 5.2 percent in 2001, from 6.5 percent in 2000, and 8 percent in 1999. A rapid decline in natural gas prices over the last three-quarters of the year as well as an increasingly competitive gas marketing environment was primarily responsible for lower margins in 2001. Most of the natural gas owned and produced by the Exploration and Production segment is sold through HPESI to third parties at variable prices based on industry pricing publications or exchange quotations. Revenues for the Company's own natural gas production are reported by the Exploration and Production segment with the Natural Gas Marketing segment retaining a market-based fee from the sale of such production. HPESI sells most of its natural gas with monthly or daily contracts tied to industry market indices, such as Inside FERC Gas Market Report. The Company, through HPESI, has natural gas delivery commitments for periods of less than a year for approximately 59 percent of its total natural gas production. At times, the Exploration and Production segment may direct HPESI to enter into fixed price natural gas sales contracts on its behalf for a small portion (normally less than 20 percent) of its natural gas sales for periods of less than 12 months to guarantee a certain price. In 2001, HPESI had approximately three percent of its natural gas sales portfolio dedicated to such fixed price sales contracts compared to 13.6 percent in 2000. As of September 30, 2001, HPESI had no long-term fixed contracts. REAL ESTATE DIVISION revenues totaled $11,018,000 for 2001, $8,999,000 for 2000, and $8,671,000 for 1999. Operating profit was $6,315,000 in 2001, $5,346,000 in 2000, and $5,338,000 in 1999. The increase in revenues and operating profit in 2001 was due to the sale of a small parcel of raw land. Occupancy rates, revenues, and operating profit remained solid in 2001 due to the continued strength of the Tulsa economy. No material changes are anticipated in the Real Estate Division in 2002. The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective October 1, 2000, which required that all derivatives be recognized 15 as assets or liabilities in the balance sheet and that these instruments be measured at fair value. The effect of SFAS No. 133 on the Company's results of operations and financial position was not material for fiscal year 2001, and is not expected to be material in 2002. In 2001, the Financial Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations," and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets." The Company does not anticipate that these pronouncements will have an immediate material impact on its results of operations or financial position. More information on these pronouncements can be found in Note 12 on page 30 of this Annual Report. LIQUIDITY AND CAPITAL RESOURCES The Company's capital spending was $274,670,000 in 2001, $131,932,000 in 2000, and $122,951,000 in 1999. Net cash provided from operating activities for those same time periods were $278,856,000 in 2001, $201,836,000 in 2000, and $158,694,000 in 1999. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $24,439,000 in 2001, $12,569,000 in 2000, and $2,803,000 in 1999. During 2000, the Company announced a program (FlexRig II program) under which it would construct 12 new FlexRigs at an approximate cost of between $7.5 and $8.25 million each. During 2001, the Company completed construction on seven of those 12 rigs. Additionally, the Company announced in 2001 that it would embark on another construction project (FlexRig III program) to build an additional 25 FlexRigs at an approximate cost of $10.2 million each. It is expected that the Company will complete construction on 15 of those 25 rigs under the FlexRig III program during 2002. During 2001, the Company also announced that it had reached agreement with two operators for offshore platform rig operations in the Gulf of Mexico. This will result in the Company spending approximately $50 million to construct two offshore platform rigs that should commence operations in the Company's third quarter of 2002. These projects, along with ongoing remodification and refurbishment of existing equipment, plus additional drill pipe and other expenditures, should bring Contract Drilling capital expenditures to approximately $340 million in 2002. Additionally, the Oil and Gas Division has estimated its capital spending needs for the coming year to be approximately $50 million. These capital expenditures, along with miscellaneous real estate and corporate 16 capital expenditures, should bring total Company capital spending for 2002 close to $400 million. Funding for this significant increase in Company capital expenditures will come from existing cash balances, internally generated cash flow, additional bank borrowings, and proceeds from securities sales. As described in Note 2 of Notes to Consolidated Financial Statements, in October 1998, the Company obtained $50 million in long-term debt proceeds. The $50 million of long-term debt matures in October 2003. The interest rate on this debt fluctuates based on the 30-day London Interbank Offered Rate (LIBOR). However, simultaneous to receiving the $50 million in long-term debt proceeds, the Company entered into a $50 million interest rate swap agreement with a major national bank. The swap effectively fixes the interest rate on this facility at 5.38 percent for the entire five-year term of the note. The Company's interest rate risk exposure is limited to its potential short-term borrowings, and results predominately from fluctuations in short-term interest rates as measured by 30-day LIBOR. This exposure should increase during 2002, as the Company secures additional debt financing. The strength of the Company's balance sheet is substantial, with current ratios for 2001 and 2000 at 2.7 and 3.4, respectively, and with total bank borrowings less than four percent of total assets at September 30, 2001. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2001, had a market value of $226,134,000, with a cost basis of $119,165,000. The portfolio, heavily weighted in energy stocks, is subject to fluctuation in the market and may vary considerably over time. Excluding the Company's equity-method investments, the portfolio is marked to market on the Company's balance sheet for each reporting period. During 2001, the Company paid a dividend of $0.30 per share, or a total of $15,047,000, representing the 30th consecutive year of dividend increases.
STOCK PORTFOLIO HELD BY THE COMPANY - --------------------------------------------------------------------------------------------- Number of September 30, 2001 Shares Cost Basis Market Value - ------------------------------------------ ----------- ------------ ------------ (in thousands, except share amounts) Atwood Oceanics, Inc. .................... 3,000,000 $ 52,152 $ 78,000 Schlumberger, Ltd. ....................... 1,480,000 23,511 67,636 Transocean Sedco Forex, Inc. ............. 286,528 9,509 7,564 SUNOCO, Inc. ............................. 312,546 2,873 11,127 Phillips Petroleum Company ............... 240,000 5,976 12,946 BANK ONE CORPORATION ..................... 175,000 1,969 5,507 Kerr-McGee Corporation ................... 150,000 3,983 7,787 Occidental Petroleum Corporation ......... 150,000 3,566 3,651 ONEOK, Inc. .............................. 450,000 2,751 7,452 Other .................................... 12,875 24,464 ------------ ------------ Total ........................ $ 119,165 $ 226,134 ============ ============
17 CONSOLIDATED BALANCE SHEETS ================================================================================ HELMERICH & PAYNE, INC.
ASSETS - ------------------------------------------------------------------------------------------------------------ September 30, 2001 2000 - ------------------------------------------------------------------------------ ---------- ---------- (in thousands) CURRENT ASSETS: Cash and cash equivalents ................................................ $ 122,962 $ 108,087 Accounts receivable, less reserve of $1,661 in 2001 and $2,003 in 2000 ... 147,235 106,630 Inventories .............................................................. 28,934 25,598 Prepaid expenses and other ............................................... 32,281 24,829 ---------- ---------- Total current assets ................................................. 331,412 265,144 ---------- ---------- INVESTMENTS .................................................................. 200,286 304,326 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment .............................................. 1,028,015 891,749 Oil and gas properties ................................................... 521,673 457,724 Real estate properties ................................................... 50,579 50,649 Other .................................................................... 86,300 80,268 ---------- ---------- 1,686,567 1,480,390 Less--Accumulated depreciation, depletion and amortization ............... 868,163 806,785 ---------- ---------- Net property, plant and equipment .................................... 818,404 673,605 OTHER ASSETS ................................................................. 14,405 16,417 ---------- ---------- TOTAL ASSETS ................................................................. $1,364,507 $1,259,492 ========== ==========
The accompanying notes are an integral part of these statements. 18
LIABILITIES AND SHAREHOLDERS' EQUITY - ---------------------------------------------------------------------------------------------------------------------- September 30, 2001 2000 - ----------------------------------------------------------------------------------- ------------ ------------ (in thousands, except share data) CURRENT LIABILITIES: Accounts payable .............................................................. $ 67,595 $ 32,279 Accrued liabilities ........................................................... 53,626 46,615 ------------ ------------ Total current liabilities ..................................... 121,221 78,894 ------------ ------------ NONCURRENT LIABILITIES: Long-term notes payable ....................................................... 50,000 50,000 Deferred income taxes ......................................................... 144,439 156,650 Other ......................................................................... 22,370 18,245 ------------ ------------ Total noncurrent liabilities .......................................... 216,809 224,895 ------------ ------------ SHAREHOLDERS' EQUITY: Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued ................................................... 5,353 5,353 Preferred stock, no par value, 1,000,000 shares authorized, no shares issued ........................................................... -- -- Additional paid-in capital .................................................... 80,324 66,090 Retained earnings ............................................................. 943,105 813,885 Unearned compensation ......................................................... (1,812) (3,277) Accumulated other comprehensive income ........................................ 49,309 106,064 ------------ ------------ 1,076,279 988,115 Less treasury stock, 3,676,155 shares in 2001 and 3,548,480 shares in 2000, at cost .................................................................... 49,802 32,412 ------------ ------------ Total shareholders' equity ............................................. 1,026,477 955,703 ------------ ------------ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ........................................ $ 1,364,507 $ 1,259,492 ============ ============
The accompanying notes are an integral part of these statements. 19 CONSOLIDATED STATEMENTS OF INCOME ================================================================================ HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999 - ------------------------------------------------ ------------ ------------ ------------ (in thousands, except per share amounts) REVENUES: Sales and other operating revenues ......... $ 816,262 $ 599,122 $ 556,562 Income from investments .................... 10,592 31,973 7,757 ------------ ------------ ------------ 826,854 631,095 564,319 ------------ ------------ ------------ COSTS AND EXPENSES: Operating costs ............................ 413,378 316,933 332,330 Depreciation, depletion and amortization ... 87,309 110,851 109,167 Dry holes and abandonments ................. 34,042 22,692 11,727 Taxes, other than income taxes ............. 41,640 29,202 25,478 General and administrative ................. 15,415 11,578 14,198 Interest ................................... (32) 3,076 6,481 ------------ ------------ ------------ 591,752 494,332 499,381 ------------ ------------ ------------ INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES ............. 235,102 136,763 64,938 INCOME TAX EXPENSE ............................. 93,027 57,684 25,706 EQUITY IN INCOME OF AFFILIATES net of income taxes ........................ 2,179 3,221 3,556 ------------ ------------ ------------ NET INCOME ..................................... $ 144,254 $ 182,300 $ 42,788 ============ ============ ============ EARNINGS PER COMMON SHARE: BASIC ...................................... $ 2.88 $ 1.66 $ 0.87 DILUTED .................................... $ 2.84 $ 1.64 $ 0.86 AVERAGE COMMON SHARES OUTSTANDING: BASIC ...................................... 50,096 49,534 49,243 DILUTED .................................... 50,772 50,035 49,817
The accompanying notes are an integral part of these statements. 20 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY ================================================================================ HELMERICH & PAYNE, INC.
Accumulated Common Stock Additional Unearned Treasury Stock Other -------------- Paid-in Comp- Retained ---------------- Comprehensive Shares Amount Capital pensation Earnings Shares Amount Income (Loss) Total ------ ------ ---------- --------- -------- ------ ------ ------------- ----------- (in thousands, except per share amounts) Balance, Sept. 30, 1998 ............ 53,529 $5,353 $59,004 $(5,605) $716,875 4,146 $(37,168) $ 54,689 $ 793,148 Comprehensive income: Net income ....................... -- -- -- -- 42,788 -- -- -- 42,788 Other comprehensive income Unrealized gains on available- for-sale securities, net ..... -- -- -- -- -- -- -- 20,493 20,493 ----------- Comprehensive income ............... 63,281 ----------- Cash dividends ($.28 per share) .... -- -- -- -- (13,866) -- -- -- (13,866) Exercise of stock options .......... -- -- 2,201 -- -- (226) 1,710 -- 3,911 Tax benefit of stock-based awards .. -- -- 69 -- -- -- -- -- 69 Stock issued under Restricted Stock Award Plan ................. -- -- 137 (289) -- (17) 152 -- -- Amortization of deferred compensation ..................... -- -- -- 1,407 159 -- -- -- 1,566 ------- ------ ------- ------- -------- ----- -------- --------- ----------- Balance, Sept. 30, 1999 ............ 53,529 5,353 61,411 (4,487) 745,956 3,903 (35,306) 75,182 848,109 Comprehensive income: Net income ....................... -- -- -- -- 82,300 -- -- -- 82,300 Other comprehensive income, Unrealized gains on available- for-sale securities, net ..... -- -- -- -- -- -- -- 30,882 30,882 ----------- Comprehensive income ............... 113,182 ----------- Cash dividends ($.285 per share) ... -- -- -- -- (14,448) -- -- -- (14,448) Exercise of stock options .......... -- -- 4,491 -- -- (366) 3,253 -- 7,744 Purchase of stock for treasury ..... -- -- -- -- -- 21 (450) -- (450) Tax benefit of stock-based awards .. -- -- 31 -- -- -- -- -- 31 Stock issued under Restricted Stock Award Plan ................. -- -- 157 (248) -- (10) 91 -- -- Amortization of deferred compensation ..................... -- -- -- 1,458 77 -- -- -- 1,535 ------- ------ ------- ------- -------- ----- -------- --------- ----------- Balance, Sept. 30, 2000 ............ 53,529 5,353 66,090 (3,277) 813,885 3,548 (32,412) 106,064 955,703 Comprehensive income: Net income ....................... -- -- -- -- 144,254 -- -- -- 144,254 Other comprehensive income, Unrealized gains on available- for-sale securities,net ...... -- -- -- -- -- -- -- (55,769) (55,769) Derivatives instruments losses, net .......................... -- -- -- -- -- -- -- (986) (986) Total other comprehensive income......................... (56,755) ----------- Comprehensive income ............... 87,499 ----------- Cash dividends ($.30 per share) .... -- -- -- -- (15,047) -- -- -- (15,047) Exercise of stock options .......... -- -- 7,965 -- -- (646) 5,808 -- 13,773 Purchase of stock for treasury ..... -- -- -- -- -- 774 (23,198) -- (23,198) Tax benefit of stock-based awards .. -- -- 6,269 -- -- -- -- -- 6,269 Amortization of deferred compensation ..................... -- -- -- 1,465 13 -- -- -- 1,478 ------- ------ ------- ------- -------- ----- -------- --------- ----------- Balance, Sept. 30, 2001 ............ 53,529 $5,353 $80,324 $(1,812) $943,105 3,676 $(49,802) $ 49,309 $ 1,026,477 ======= ====== ======= ======= ======== ===== ======== ========= ===========
The accompanying notes are an integral part of these statements. 21 CONSOLIDATED STATEMENTS OF CASH FLOWS ================================================================================ HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999 - ---------------------------------------------------------------------------- ---------- ---------- ---------- (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income .............................................................. $ 144,254 $ 182,300 $ 42,788 ---------- ---------- ---------- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ........................... 87,309 110,851 109,167 Dry holes and abandonments ......................................... 34,042 22,692 11,727 Equity in income of affiliates before income taxes ................. (4,383) (5,196) (5,735) Amortization of deferred compensation .............................. 1,478 1,535 1,566 Gain on sale of securities and non-monetary investment income ...... (1,189) (24,000) (2,547) Gain on sale of property, plant and equipment ...................... (4,895) (2,479) (6,900) Other - net ........................................................ 906 944 2,148 Change in assets and liabilities: Accounts receivable ............................................. (39,747) (7,032) 19,797 Inventories ..................................................... (2,062) (411) 214 Prepaid expenses and other ...................................... (4,874) (7,780) (5,079) Accounts payable ................................................ 34,840 6,575 (16,147) Accrued liabilities ............................................. 9,065 7,557 2,367 Deferred income taxes ........................................... 21,641 21,133 559 Other noncurrent liabilities .................................... 2,471 (4,853) 4,769 ---------- ---------- ---------- 134,602 119,536 115,906 ---------- ---------- ---------- Net cash provided by operating activities .................... 278,856 201,836 158,694 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, including dry hole costs .......................... (274,670) (131,932) (122,951) Acquisition of business, net of cash acquired ........................... (2,279) -- -- Proceeds from sale of property, plant and equipment ..................... 13,173 18,044 9,990 Purchase of investments ................................................. -- -- (537) Proceeds from sale of securities ........................................ 24,439 12,569 2,803 ---------- ---------- ---------- Net cash used in investing activities ........................ (239,337) (101,319) (110,695) ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from notes payable ............................................. -- -- 102,000 Payments made on notes payable .......................................... -- (5,000) (141,800) Dividends paid .......................................................... (15,047) (14,175) (13,849) Purchases of stock for treasury ......................................... (23,198) (450) -- Proceeds from exercise of stock options ................................. 13,601 5,437 2,932 ---------- ---------- ---------- Net cash used in financing activities ........................ (24,644) (14,188) (50,717) ---------- ---------- ---------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ............................................................. 14,875 86,329 (2,718) CASH AND CASH EQUIVALENTS, beginning of period ............................. 108,087 21,758 24,476 ---------- ---------- ---------- CASH AND CASH EQUIVALENTS, end of period ................................... $ 122,962 $ 108,087 $ 21,758 ========== ========== ==========
The accompanying notes are an integral part of these statements. 22 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ================================================================================ HELMERICH & PAYNE, INC. September 30, 2001, 2000 and 1999 - -------------------------------------------------------------------------------- NOTE 1 SUMMARY OF ACCOUNTING POLICIES - -------------------------------------------------------------------------------- CONSOLIDATION - The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and all of its wholly-owned subsidiaries. Fiscal years of the Company's foreign consolidated operations end on August 31 to facilitate reporting of consolidated results. TRANSLATION OF FOREIGN CURRENCIES - The Company has determined that the functional currency for its foreign subsidiaries is the U.S. dollar. The foreign currency transaction loss for 2001, 2000, and 1999 was $494,000, $664,000, and $21,000, respectively. USE OF ESTIMATES - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. PROPERTY, PLANT AND EQUIPMENT - The Company follows the successful efforts method of accounting for oil and gas properties. Under this method, the Company capitalizes all costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells which find proved reserves and to drill and equip development wells. Geological and geophysical costs, delay rentals and costs to drill exploratory wells which do not find proved reserves are expensed. Capitalized costs of producing oil and gas properties are depreciated and depleted by the unit-of-production method based on proved oil and gas reserves as determined by the Company and its independent engineers. Reserves are recorded for capitalized costs of undeveloped leases based on management's estimate of recoverability. Costs of surrendered leases are charged to the reserve. In accordance with Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Company recognizes impairment losses for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the carrying amount of the asset. The Company recognized impairment charges of approximately $8.9 million, $4.0 million and $10.1 million in 2001, 2000, and 1999, respectively, for proved Exploration and Production properties which are included in depreciation, depletion, and amortization expense. After-tax, the impairment charge reduced 2001, 2000, and 1999 net income by approximately $5.5 million, $2.5 million, and $6.2 million, respectively. On a diluted basis the impairment charges reduced earnings per share in 2001, 2000, and 1999 by $0.11, $0.05, and $0.13, respectively. The Company evaluates impairment of exploration and production assets on a field by field basis. Fair value on all long-lived assets is based on discounted future cash flows or information provided by sales and purchases of similar assets. Substantially all property, plant and equipment other than oil and gas properties is depreciated using the straight-line method based on the following estimated useful lives:
YEARS ----- Contract drilling equipment...................... 4-15 Real estate buildings and equipment.............. 10-50 Other............................................ 3-33
As a result of an economic evaluation of useful lives of its drilling equipment, the Company extended the depreciable life of its rig equipment from ten to 15 years. This change will provide a better matching of revenues and depreciation expense over the useful life of the equipment. This change, effective October 1, 2000, reduced depreciation expense for 2001 by approximately $30 million. CASH AND CASH EQUIVALENTS - Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which mature within three months from the date of purchase. INVENTORIES - Inventories, primarily materials and supplies, are valued at the lower of cost (moving average or actual) or market. SHIPPING COSTS - The Company's shipping and handling costs are included under operating costs for all periods presented. DRILLING REVENUES - Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and expenses are recognized as work progresses. Fiscal 2000 and 1999 contract drilling revenues also include revenues of $4,109,000, and $40,790,000, respectively, from a rig construction contract for which revenues were recognized based on the percentage-of-completion method, measured by the percentage that incurred costs to date bear to total estimated costs. The Company does not currently have any third party rig construction contracts. GAS IMBALANCES - The Company recognizes revenues from gas wells on the sales method, and a liability is recorded for permanent imbalances resulting from gas wells in which the Company has sold more production than it is entitled. INVESTMENTS - The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. Net income in 2001 includes a loss of approximately $1.4 million, $0.03 per share on a diluted basis, resulting from the Company's assessment that the decline in market value of certain available-for-sale securities below their financial cost basis was other than temporary. Net income in 2000 included approximately $6.6 million, $0.13 per share on a diluted basis, on gains related to non-monetary transactions within the Company's available-for-sale security invested portfolio which were accounted for at fair value. Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the Company recognizing its proportionate share of the income or loss of each investee. The Company owned approximately 22% of Atwood Oceanics, Inc. (Atwood) at both September 30, 2001 and 2000. The quoted market value of the Company's investment was $78,000,000 and $125,063,000 at September 30, 2001 and 2000, respectively. Retained earnings at September 30, 2001 includes approximately $25,514,000 of undistributed earnings of Atwood. 23 Summarized financial information of Atwood is as follows:
2001 2000 1999 ---------- ---------- ---------- (in thousands) Gross revenues ................................... $ 147,540 $ 134,514 $ 150,009 Costs and expenses ............................... 120,395 111,366 122,289 ---------- ---------- ---------- Net income ....................................... $ 27,145 $ 23,148 $ 27,720 ========== ========== ========== Helmerich & Payne, Inc.'s equity in net income, net of income taxes ........................ $ 3,596 $ 3,221 $ 3,556 ========== ========== ========== Current assets ................................... $ 45,891 $ 63,951 $ 50,532 Noncurrent assets ................................ 304,857 248,334 243,072 Current liabilities .............................. 19,144 17,484 19,013 Noncurrent liabilities ........................... 85,948 77,332 82,362 Shareholders' equity ............................. 245,656 217,469 192,229 ========== ========== ========== Helmerich & Payne, Inc.'s investment ............. $ 52,153 $ 46,353 $ 41,157 ========== ========== ==========
INCOME TAXES - Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company's assets and liabilities. OTHER POST EMPLOYMENT BENEFITS - The Company sponsors a health care plan that provides post retirement medical benefits to retired employees. Employees who retire after November 1, 1992 and elect to participate in the plan pay the entire estimated cost of such benefits. The Company has accrued a liability for estimated workers compensation claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material. EARNINGS PER SHARE - Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per share includes the dilutive effect of stock options and restricted stock. EMPLOYEE STOCK-BASED AWARDS - Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related information. Fixed plan common stock options do not result in compensation expense, because the exercise price of the stock equals the market price of the underlying stock on the date of grant. TREASURY STOCK - Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in-capital using the average-cost method. CAPITALIZATION OF INTEREST - The Company capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds, with the rate based on the average interest rate on related debt. Capitalized interest for 2001, 2000, and 1999 was $1.3 million, $0.4 million, and $0.1 million, respectively. INTEREST RATE RISK MANAGEMENT - The Company uses derivatives as part of an overall operating strategy to moderate certain financial market risks and is exposed to interest rate risk from long-term debt. To manage this risk, in October 1998, the Company entered into an interest rate swap to exchange floating rate for fixed rate interest payments through October 2003, the remaining life of the debt. The difference to be paid or received is accrued and recognized as an adjustment of interest expense. As of September 30, 2001, the Company's interest rate swap had a notional principal amount of $50 million. The Company's accounting policy for these instruments is based on its designation of such instruments as hedging transactions. An instrument is designated as a hedge based in part on its effectiveness in risk reduction and one-to-one matching of derivative instruments to underlying transactions. The Company records all derivatives on the balance sheet at fair value. For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure of variability in expected future cash flows that is attributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income in stockholders' equity and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The change in value of the derivative instrument in excess of the cumulative change in the present value of the future cash flows of the risk being hedged, if any, is recognized in the current earnings during the period of change. The Company's interest rate swap has been designated as a cash flow hedge and is 100% effective in hedging the exposure of variability in the future interest payments attributable to the debt because the terms of the interest swap correlate with the terms of the debt. Gains and losses from termination of interest rate swap agreements are deferred and amortized as an adjustment to interest expense over the original term of the terminated swap agreement. - -------------------------------------------------------------------------------- NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT - -------------------------------------------------------------------------------- At September 30, 2001, the Company had committed bank lines totaling $85 million; $50 million expires October 2003 and $35 million expires May 2002. Additionally, the Company had uncommitted credit facilities totaling $10 million. Collectively, the Company had $50 million in outstanding borrowings and outstanding letters of credit totaling $10.6 million against these lines at September 30, 2001. As described above, concurrent with a $50 million borrowing under the facility that expires October 2003, the Company entered into an interest rate swap with a notional value of $50 million and an expiration date of October 2003. The swap effectively converts this $50 million facility from a floating rate of LIBOR plus 50 basis points to a fixed effective rate of 5.38 percent. Excluding the impact of the interest rate swap, the average interest rate for the borrowings at September 30, 2001, was approximately 5.66 percent on a 360 day basis. Under the various credit agreements, the Company must meet certain requirements regarding levels of debt, net worth and earnings. 24 - -------------------------------------------------------------------------------- NOTE 3 INCOME TAXES - -------------------------------------------------------------------------------- The components of the provision (benefit) for income taxes are as follows:
Years Ended September 30, 2001 2000 1999 - -------------------------------------------------------------------- --------- ---------- -------- (in thousands) CURRENT: Federal........................................................... $ 57,607 $ 325,736 $ 9,684 Foreign......................................................... 8,870 8,766 15,963 State........................................................... 6,680 3,366 1,744 --------- ---------- -------- 73,157 37,868 27,391 --------- ---------- -------- DEFERRED: Federal......................................................... 14,020 12,318 (842) Foreign......................................................... 4,701 6,146 (771) State .......................................................... 1,149 1,352 (72) --------- ---------- -------- 19,870 19,816 (1,685) --------- ---------- -------- TOTAL PROVISION: $ 93,027 $ 57,684 $ 25,706 ========= ========== ========
The amounts of domestic and foreign income are as follows:
Years Ended September 30, 2001 2000 1999 - -------------------------------------------------------------------- --------- ---------- -------- (in thousands) INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES: Domestic........................................................ $ 208,288 $ 129,373 $ 41,693 Foreign......................................................... 26,814 7,390 23,245 --------- ---------- -------- $ 235,102 $ 136,763 $ 64,938 ========= ========== ========
Effective income tax rates on income as compared to the U.S. Federal income tax rate are as follows:
Years Ended September 30, 2001 2000 1999 - --------------------------------------------------------------------- --------- -------- -------- U.S. Federal income tax rate......................................... 35% 35% 35% Dividends received deduction......................................... -- -- (1) Effect of foreign taxes.............................................. 2 5 5 Non-conventional fuel source credits utilized........................ -- -- (1) Other, net........................................................... 3 2 2 --- --- --- Effective income tax rate............................................ 40% 42% 40% === === ===
The components of the Company's net deferred tax liabilities are as follows:
September 30, 2001 2000 - --------------------------------------------------- ----------- ---------- (in thousands) DEFERRED TAX LIABILITIES: Property, plant and equipment $ 101,674 $ 75,653 Available-for-sale securities 33,937 72,583 Pension provision 3,194 4,075 Equity investments 15,637 12,734 Other 506 1,217 ----------- ---------- Total deferred tax liabilities 154,948 166,262 ----------- ---------- DEFERRED TAX ASSETS: Financial accruals 6,746 9,612 Other 3,763 -- Total deferred tax assets 10,509 9,612 ----------- ---------- NET DEFERRED TAX LIABILITIES $ 144,439 $ 156,650 =========== ==========
25 - -------------------------------------------------------------------------------- NOTE 4 SHAREHOLDERS' EQUITY - -------------------------------------------------------------------------------- In January 2000, the board of directors authorized the repurchase of up to 1,000,000 shares of the Company's common stock in the open market or private transactions. The repurchased shares will be held in treasury and used for general corporate purposes including use in the Company's benefit plans. During fiscal 2001, the Company purchased 773,800 shares at a cost of approximately $23,198,000 and in fiscal 2000 purchased 20,600 shares at a cost of approximately $450,000. The Company did not purchase any shares is fiscal 1999. As of September 30, 2001, the Company is authorized to repurchase up to 205,600 additional shares. The Company has several plans providing for common-stock based awards to employees and to non-employee directors. The plans permit the granting of various types of awards including stock options and restricted stock. Awards may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire ten years after grant. The Company has reserved 3,135,509 shares of its treasury stock to satisfy the exercise of stock options issued under the 1990 and 1996 Stock Option Plans. Effective after December 6, 2000, additional options are no longer granted under these Plans. Options granted under the 1996 Plan vest over a four-year period. In fiscal 2001, 843,800 options were granted under the 1996 Plan. In March 2001, the Company adopted the 2000 Stock Incentive Plan (the "Stock Incentive Plan"). The Stock Incentive Plan was effective December 6, 2000, and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options for up to 3,000,000 shares of the Company's common stock at an exercise price not less than the fair market value of the common stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock awards. There was no activity under this plan during fiscal 2001. In fiscal 2000 and 1999, 10,000 and 17,000 shares of restricted stock, respectively, were granted at a weighted-average price of $24.75 and $17.00, respectively, which approximated fair market value at the date of grant. Unearned compensation of $248,000 and $289,000 for fiscal 2000 and 1999, respectively, is being amortized over a five-year period as compensation expense. There were no restricted stock grants in fiscal 2001. The following summary reflects the stock option activity and related information (shares in thousands):
2001 2000 1999 ---------------------------- --------------------------- -------------------------- Weighted-Average Weighted-Average Weighted-Average Options Exercise Price Options Exercise Price Options Exercise Price ------- ---------------- ------- ---------------- ------- ---------------- Outstanding at October 1, 2,955 $22.94 2,574 $21.34 2,090 $22.09 Granted 844 32.36 767 24.75 726 16.81 Exercised (644) 21.34 (364) 15.44 (238) 14.28 Forfeited/Expired (19) 25.57 (22) 23.00 (4) 13.51 ------- -------- ------- -------- ------ -------- Outstanding on September 30, 3,136 $25.78 2,955 $22.94 2,574 $21.34 ------- -------- ------- -------- ------ -------- Exercisable on September 30, 1,078 $23.82 1,046 $22.40 782 $20.13 ------- -------- ------- -------- ------ -------- Shares available on September 30, for options that may be granted 3,000 1,777 2,537 ------- ------- ------
The following table summarizes information about stock options at September 30, 2001 (shares in thousands):
Outstanding Stock Options Exercisable Stock Options ----------------------------------------------------- ---------------------------- Weighted-Average Range of Remaining Contractural Weighted-Average Weighted-Average Exercise Prices Options Life Exercise Price Options Exercise Price - -------------------- ------- ---------------------- ---------------- ------- ---------------- $12.00 to $16.50 374 3.7 years $13.78 284 $13.77 $16.51 to $26.50 1,511 7.3 years $22.08 511 $22.18 $26.51 to $38.31 1,251 8.2 years $33.84 283 $36.85 ------ --------- ------ ----- ------ $12.00 to $38.31 3,136 7.2 years $25.78 1,078 $23.82 ------ --------- ------ ----- ------
26 The following table reflects pro forma net income and earnings per share had the Company elected to adopt the fair value method of SFAS No. 123, "Accounting for Stock-Based Compensation," in measuring compensation cost beginning with 1997 employee stock-based awards.
Years Ended September 30, 2001 2000 1999 - ------------------------------------------ ------------ ------------ ----------- (in thousands, except per share data) Net Income: As reported ........................... $ 144,254 $ 82,300 $ 42,788 Pro forma ............................. $ 139,211 $ 78,788 $ 40,268 Basic earnings per share: As reported ........................... $ 2.88 $ 1.66 $ .87 Pro forma ............................. $ 2.78 $ 1.59 $ .82 Diluted earnings per share: As reported ........................... $ 2.84 $ 1.64 $ .86 Pro forma ............................. $ 2.74 $ 1.57 $ .81
These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period, and additional options may be granted in future years. The weighted-average fair values of options at their grant date during 2001, 2000, and 1999 were $13.01, $10.80, and $6.81, respectively. The estimated fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model:
2001 2000 1999 ---- ---- ---- Expected years until exercise..................................... 4.5 5.5 5.5 Expected stock volatility......................................... 43% 41% 38% Dividend yield.................................................... .8% .8% 1.2% Risk-free interest rate........................................... 5.2% 6.0% 6.0%
On September 30, 2001, the Company had 49,852,797 outstanding common stock purchase rights ("Rights") pursuant to terms of the Rights Agreement dated January 8, 1996. Under the terms of the Rights Agreement each Right entitled the holder thereof to purchase from the Company one half of one unit consisting of one one-thousandth of a share of Series A Junior Participating Preferred Stock ("Preferred Stock"), without par value, at a price of $90 per unit. The exercise price and the number of units of Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be attached to the common stock certificates and are not exercisable or transferrable apart from the common stock, until ten business days after a person acquires 15% or more of the outstanding common stock or ten business days following the commencement of a tender offer or exchange offer that would result in a person owning 15% or more of the outstanding common stock. In the event the Company is acquired in a merger or certain other business combination transactions (including one in which the Company is the surviving corporation), or more than 50% of the Company's assets or earning power is sold or transferred, each holder of a Right shall have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the exercise price of the Right. The Rights are redeemable under certain circumstances at $0.01 per Right and will expire, unless earlier redeemed, on January 31, 2006. As long as the Rights are not separately transferrable, the Company will issue one half of one Right with each new share of common stock issued. - -------------------------------------------------------------------------------- NOTE 5 EARNINGS PER SHARE - -------------------------------------------------------------------------------- A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: (in thousands) 2001 2000 1999 - -------------------------------------------------------------- -------- -------- -------- Basic weighted-average shares.............................. 50,096 49,534 49,243 Effect of dilutive shares: Stock options............................................ 644 492 561 Restricted stock......................................... 32 9 13 ------ ------ ------ 676 501 574 ------ ------ ------ Diluted weighted-average shares............................... 50,772 50,035 49,817 ====== ====== ======
Restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 1,250,750 shares of common stock at a weighted-average price of $33.84 were outstanding at September 30, 2001 but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 2000, restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 533,000 shares of common stock at a price of $36.84 were outstanding but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 1999, restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 540,000 shares of common stock at a price of $36.84 were outstanding but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. 27 - -------------------------------------------------------------------------------- NOTE 6 FINANCIAL INSTRUMENTS - -------------------------------------------------------------------------------- Notes payable bear interest at market rates and are carried at cost which approximates fair value. The estimated fair value of the Company's interest rate swap is ($1,590,553) at September 30, 2001, based on forward-interest rates derived from the year-end yield curve as calculated by the financial institution that is a counterparty to the swap. The estimated fair value of the Company's available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1):
Gross Gross Estimated Unrealized Unrealized Fair Cost Gains Losses Value -------- ---------- ---------- --------- (in thousands) Equity Securities: September 30, 2001 $63,778 $ 84,257 $3,136 $144,899 September 30, 2000 $86,901 $173,137 $2,065 $257,973
During the years ended September 30, 2001, 2000, and 1999, marketable equity available-for-sale securities with a fair value at the date of sale of $24,439,000, $12,640,000, and $2,803,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $3,314,000, $12,576,000, and $2,547,000, respectively, and the gross realized losses totaled $0, $0, and $0 respectively. - -------------------------------------------------------------------------------- NOTE 7 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) - -------------------------------------------------------------------------------- The table below presents changes in the components of accumulated other comprehensive income (loss).
Unrealized Appreciation Interest (Depreciation) on Securities Rate Swap Total ---------------------------- --------- ----- Balance at September 30, 1998................................... $ 54,689 $ -- $ 54,689 1999 Change: Pre-income tax amount...................................... 35,600 -- 35,600 Income tax provision....................................... (13,528) -- (13,528) Realized gains in net income (net of $968 income tax)...... (1,579) -- (1,579) -------- ------- -------- ............................................................. 20,493 -- 20,493 -------- ------- -------- Balance at September 30, 1999................................... 75,182 -- 75,182 -------- ------- -------- 2000 Change: Pre-income tax amount...................................... 73,810 -- 73,810 Income tax provision....................................... (28,048) -- (28,048) Realized gains in net income (net of $9,120 income tax).... (14,880) -- (14,880) -------- ------- -------- ............................................................. 30,882 -- 30,882 -------- ------- -------- Balance at September 30, 2000................................... 106,064 -- 106,064 -------- ------- -------- 2001 Change: Pre-income tax amount...................................... (88,762) (1,590) (90,352) Income tax provision....................................... 33,730 604 34,334 Realized gains in net income (net of $452 income tax)...... (737) -- (737) -------- ------- -------- ............................................................. (55,769) (986) (56,755) -------- ------- -------- Balance at September 30, 2001................................... $ 50,295 $ (986) $ 49,309 ======== ======= ========
- -------------------------------------------------------------------------------- NOTE 8 EMPLOYEE BENEFIT PLANS - -------------------------------------------------------------------------------- The following tables set forth the Company's disclosures required by SFAS No. 132, "Employers' Disclosures About Pensions and Other Postretirement Benefits". CHANGE IN BENEFIT OBLIGATION:
Years ended September 30, 2001 2000 - ----------------------------------------------------------------------------- ------- ------- (in thousands) Benefit obligation at beginning of year................................... $44,838 $36,995 Service cost.............................................................. 3,851 3,427 Interest cost............................................................. 3,330 2,741 Actuarial loss ........................................................... 903 3,059 Benefits paid............................................................. (1,189) (1,384) ------- ------- Benefit obligation at end of year......................................... $51,733 $44,838 ======= =======
CHANGE IN PLAN ASSETS:
Years ended September 30, 2001 2000 - ----------------------------------------------------------------------------- ------- ------- (in thousands) Fair value of plan assets at beginning of year............................ $60,611 $ 58,517 Actual return (loss) on plan assets....................................... (5,435) 3,478 Benefits paid............................................................. (1,189) (1,384) ------- -------- Fair value of plan assets at end of year ................................. $53,987 $ 60,611 ======= ======== Funded status of the plan................................................. $ 2,254 $ 15,773 Unrecognized net actuarial (gain) loss.................................... 6,720 (5,016) Unrecognized prior service cost........................................... 548 786 Unrecognized net transition asset......................................... (540) (1,079) ------- -------- Prepaid benefit cost...................................................... $ 8,982 $(10,464) ======= ========
28 WEIGHTED-AVERAGE ASSUMPTIONS:
Years Ended September 30, 2001 2000 1999 - -------------------------------------- ------- ------ ------- Discount rate 7.50% 7.50% 7.50% Expected return on plan 9.00% 9.00% 9.00% Rate of compensation increase 5.00% 5.00% 5.00%
COMPONENTS OF NET PERIODIC PENSION EXPENSE:
Years Ended September 30, 2001 2000 1999 - -------------------------------------------------------------- ------- -------- -------- (in thousands) Service cost............................................... $ 3,851 $ 3,427 $ 3,700 Interest cost.............................................. 3,330 2,741 2,468 Expected return on plan assets............................. (5,415) (5,226) (4,606) Amortization of prior service cost......................... 238 238 238 Amortization of transition asset........................... (540) (540) (540) Recognized net actuarial gain.............................. 17 (303) 14 ------- ------- ------- Net pension expense........................................ $ 1,481 $ (337) $ 1,274 ======= ======= =======
DEFINED CONTRIBUTION PLAN: Substantially all employees on the United States payroll of the Company may elect to participate in the Company sponsored Thrift/401(k) Plan by contributing a portion of their earnings. The Company contributes amounts equal to 100 percent of the first five percent of the participant's compensation subject to certain limitations. Expensed Company contributions were $4,935,000, $3,545,000, and $3,315,000 in 2001, 2000, and 1999, respectively. - -------------------------------------------------------------------------------- NOTE 9 ACCRUED LIABILITIES - -------------------------------------------------------------------------------- Accrued liabilities consist of the following:
September 30, 2001 2000 - ----------------------------------------------------------------------------- -------- -------- (in thousands) Royalties payable......................................................... $13,527 $18,918 Taxes payable - operations................................................ 9,996 6,861 Ad valorem tax............................................................ 354 7,783 Income taxes payable...................................................... 739 -- Workers compensation claims............................................... 2,585 2,840 Payroll and employee benefits............................................. 5,676 4,055 Loss contingency (see note 13)............................................ 10,000 -- Other..................................................................... 10,749 6,158 ------- ------- $53,626 $46,615 ======= =======
- -------------------------------------------------------------------------------- NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION - --------------------------------------------------------------------------------
Years Ended September 30, 2001 2000 1999 - -------------------------------------------------------------- ------- -------- -------- (in thousands) CASH PAYMENTS: Interest paid.............................................. $ 5,030 $ 2,491 $ 5,705 Income taxes paid.......................................... $73,039 $39,673 $27,843
- -------------------------------------------------------------------------------- NOTE 11 RISK FACTORS - -------------------------------------------------------------------------------- CONCENTRATION OF CREDIT - Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments and trade receivables. The Company places temporary cash investments with established financial institutions and invests in a diversified portfolio of highly rated, short-term money market instruments. The Company's trade receivables are primarily with companies in the oil and gas industry. The Company normally does not require collateral except for certain receivables of customers in its natural gas marketing operations. CONTRACT DRILLING OPERATIONS - International drilling operations are significant contributors to the Company's revenues and net profit. It is possible that operating results could be affected by the risks of such activities, including economic conditions in the international markets in which the Company operates, political and economic instability, fluctuations in currency exchange rates, changes in international regulatory requirements, international employment issues, and the burden of complying with foreign laws. These risks may adversely affect the Company's future operating results and financial position. The Company believes that its rig fleet is not currently impaired based on an assessment of future cash flows of the assets in question. However, it is possible that the Company's assessment that it will recover the carrying amount of its rig fleet from future operations may change in the near term. OIL AND GAS OPERATIONS - In estimating future cash flows attributable to the Company's exploration and production assets, certain assumptions are made with regard to commodity prices received and costs incurred. Due to the volatility of commodity prices, it is possible that the Company's assumptions used in estimating future cash flows for exploration and production assets may change in the near term. 29 - -------------------------------------------------------------------------------- NOTE 12 NEW ACCOUNTING STANDARDS - -------------------------------------------------------------------------------- Effective October 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities," as amended, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133, as amended, requires that all derivatives be recorded on the balance sheet at fair value. Upon adoption at October 1, 2000, the effect of complying with SFAS 133, as amended, was immaterial to the Company's results of operations and financial position. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The effect of this standard on the Company's results of operations and financial position is being evaluated. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The Statement retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. The Statement will be applied prospectively and is effective for financial statements issued for fiscal years beginning after December 15, 2001. Adoption of the Statement is not expected to have any initial impact on the Company's results of operations or financial position. - -------------------------------------------------------------------------------- NOTE 13 CONTINGENT LIABILITIES AND COMMITMENTS - -------------------------------------------------------------------------------- LITIGATION SETTLEMENT - As previously discussed in the Company's filings on Forms 8-K dated March 16, 2001, and June 13, 2001, and in the Company's Form 10-Q filed on August 13, 2001, the Company is a defendant in Verdin v. R&B Falcon Drilling USA, Inc., et al., a civil action in the United States District Court, Galveston, Texas. The lawsuit alleges, among other things, that the company and many other defendant companies whose collective operations represent a substantial majority of the U.S. offshore drilling industry, conspired to fix wages and benefits paid to drilling employees. Plaintiff contends that this alleged conduct violates federal and state antitrust laws. Plaintiff sought treble damages, attorneys' fees and costs on behalf of himself and an alleged class of offshore workers. In May 2001, the Company reached an agreement in principle with Plaintiff's counsel to settle all claims pending court approval of the settlement. In the third quarter of fiscal 2001, the Company accrued $3.25 million to contract drilling expense based on the pending settlement. The total settlement liability is $10 million of which $6.75 million will be paid by the Company's insurer. The Company does not believe that the settlement will have a material adverse affect on its business or financial position. KANSAS AD VALOREM SETTLEMENT - In fiscal 1997, the Company was assessed with approximately $6.7 million of Kansas ad valorem taxes which had been reimbursed to the Company for the period from October 1983 through June 1988 by interstate pipelines transporting natural gas to end users. In fiscal 1997, based on the assessment, natural gas revenues were reduced by $2.7 million and interest expense was increased by $4.0 million. In March 1998, approximately $6.1 million of the unpaid assessment was placed in an escrow account pending resolution of this matter. Since March 1998, the escrow account and the related liability continued to accrue interest income and interest expense of approximately $1.0 million. The Federal Energy Regulatory Commission approved settlements between the Company and three of the pipelines. The last of these settlements was final in May 2001. The Company paid approximately $3.9 million out of its escrow account for the settlement of all three pipeline proceedings. The three settlements were approximately $3.1 million less than the amount the Company accrued for this liability. The impact of these settlements in the third quarter of fiscal 2001 was to increase natural gas revenues by approximately $1.1 million, reduce interest expense by approximately $2.0 million and reduce the liability by $3.1 million. At September 30, 2001, the Company continues to escrow approximately $337,000 to cover reimbursement liability in the remaining two pipeline proceedings. The Company believes this amount will be adequate to cover future reimbursement liability. COMMITMENTS - The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2001, the Company has commitments of approximately $230 million for the purchase of drilling equipment. - -------------------------------------------------------------------------------- NOTE 14 SEGMENT INFORMATION - -------------------------------------------------------------------------------- The Company operates principally in the contract drilling industry, which includes a Domestic segment and an International segment, and in the oil and gas industry, which includes an Exploration and Production segment and a Natural Gas Marketing segment. The contract drilling operations consist of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company's primary international areas of operation include Venezuela, Colombia, Ecuador, Argentina and Bolivia. Oil and gas activities include the exploration for and development of productive oil and gas properties located primarily in Oklahoma, Texas, Kansas, and Louisiana, as well as, the marketing of natural gas for third parties. The Natural Gas Marketing segment also markets most of the natural gas produced by the Exploration and Production segment retaining a market based fee from the sale of such production. The Company also has a Real Estate segment whose operations are conducted exclusively in the metropolitan area of Tulsa, Oklahoma. The primary areas of operations include a major shopping center and several multi-tenant warehouses. Each reportable segment is a strategic business unit which is managed separately as an autonomous business. Other includes investments in available-for-sale securities and corporate operations. The "other" component of Total Assets also includes the Company's investment in equity-owned investments. The Company evaluates performance of its segments based upon operating profit or loss from operations before income taxes which includes revenues from external and internal customers; operating costs; depreciation, depletion and amortization; dry holes and abandonments and taxes other than income taxes. The accounting policies of the segments are the same as those described in Note 1, Summary of Accounting Policies. Intersegment sales are accounted for in the same manner as sales to unaffiliated customers. 30 Summarized financial information of the Company's reportable segments for each of the years ended September 30, 2001, 2000, and 1999 is shown in the following table:
Depreciation Additions External Inter- Total Operating Depletion & Total to Long-Lived (in thousands) Sales Segment Sales Profit Amortization Assets Assets - -------------- -------- -------- -------- --------- ------------ ---------- ------------- 2001: CONTRACT DRILLING Domestic.......................... $332,399 $ 4,487 $336,886 $107,691 $ 25,890 $ 506,173 $144,063 International Services............ 154,890 -- 154,890 28,475 18,838 268,947 38,022 -------- -------- -------- -------- -------- ---------- -------- 487,289 4,487 491,776 136,166 44,728 775,120 182,085 -------- -------- -------- -------- -------- ---------- -------- OIL & GAS OPERATIONS Exploration and Production........ 217,194 -- 217,194 95,579 38,104 190,907 89,733 Natural Gas Marketing............. 100,111 -- 100,111 5,254 170 14,598 269 -------- -------- -------- -------- -------- ---------- -------- 317,305 -- 317,305 100,833 38,274 205,505 90,002 -------- -------- -------- -------- -------- ---------- -------- REAL ESTATE......................... 11,018 1,545 12,563 6,315 2,264 22,621 1,190 OTHER............................... 11,242 -- 11,242 -- 2,043 361,261 1,393 ELIMINATIONS........................ -- (6,032) (6,032) -- -- -- -- -------- -------- -------- -------- -------- ---------- -------- TOTAL........................... $826,854 $ -- $826,854 $243,314 $ 87,309 $1,364,507 $274,670 ======== ======== ======== ======== ======== ========== ======== 2000: CONTRACT DRILLING Domestic.......................... $214,531 $ 3,048 $217,579 $ 35,808 $ 35,310 $ 342,278 $ 40,722 International..................... 136,549 136,549 9,753 38,096 259,892 13,825 -------- -------- -------- -------- -------- ---------- -------- 351,080 3,048 354,128 45,561 73,406 602,170 54,547 -------- -------- -------- -------- -------- ---------- -------- OIL & GAS OPERATIONS Exploration and Production........ 157,583 -- 157,583 66,604 33,462 174,466 65,804 Natural Gas Marketing............. 80,907 -- 80,907 5,271 164 21,897 175 -------- -------- -------- -------- -------- ---------- -------- 238,490 -- 238,490 71,875 33,626 196,363 65,979 -------- -------- -------- -------- -------- ---------- -------- REAL ESTATE......................... 8,999 1,545 10,544 5,346 1,598 24,235 2,909 OTHER............................... 32,526 -- 32,526 -- 2,221 436,724 8,497 ELIMINATIONS........................ -- (4,593) (4,593) -- -- -- -- -------- -------- -------- -------- -------- ---------- -------- TOTAL........................... $631,095 $ -- $631,095 $122,782 $110,851 $1,259,492 $131,932 ======== ======== ======== ======== ======== ========== ======== 1999: CONTRACT DRILLING Domestic.......................... $213,647 $ 2,457 $216,104 $ 30,154 $ 31,164 $ 371,766 $ 57,975 International..................... 182,987 -- 182,987 29,845 36,178 271,746 17,293 -------- -------- -------- -------- -------- ---------- -------- 396,634 2,457 399,091 59,999 67,342 643,512 75,268 -------- -------- -------- -------- -------- ---------- -------- OIL & GAS OPERATIONS Exploration and Production........ 95,953 -- 95,953 11,245 38,658 151,898 44,333 Natural Gas Marketing............. 55,259 -- 55,259 4,418 174 15,156 261 -------- -------- -------- -------- -------- ---------- -------- 151,212 -- 151,212 15,663 38,832 167,054 44,594 -------- -------- -------- -------- -------- ---------- -------- REAL ESTATE......................... 8,671 1,531 10,202 5,338 1,427 22,816 1,445 OTHER............................... 7,802 -- 7,802 -- 1,566 276,317 1,644 ELIMINATIONS........................ -- (3,988) (3,988) -- -- -- -- -------- -------- -------- -------- -------- ---------- -------- TOTAL........................... $564,319 $ -- $564,319 $ 81,000 $109,167 $1,109,699 $122,951 ======== ======== ======== ======== ======== ========== ========
The following table reconciles segment operating profit per the table on page 31 to income before taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands).
Years Ended September 30, 2001 2000 1999 - ---------------------------------------- -------- -------- -------- Segment operating profit.................. $243,314 $122,782 $ 81,000 Unallocated amounts: Income from investments................. 10,592 31,973 7,757 General and administrative expense...... (15,415) (11,578) (14,198) Interest expense........................ 32 (3,076) (6,481) Corporate depreciation.................. (2,043) (2,152) (1,565) Other corporate expense................. (1,378) (1,186) (1,575) -------- -------- -------- Total unallocated amounts............. (8,212) 13,981 (16,062) -------- -------- -------- Income before income taxes and equity in income of affiliates................. $235,102 $136,763 $ 64,938 ======== ======== ========
31 The following tables present revenues from external customers and long-lived assets by country based on the location of service provided (in thousands).
Years Ended September 30, 2001 2000 1999 - ------------------------------------------------- ---------- ---------- ---------- Revenues United States ............................ $ 671,964 $ 494,546 $ 381,332 Venezuela ................................ 43,409 34,922 59,481 Colombia ................................. 27,045 42,509 60,838 Other Foreign ............................ 84,436 59,118 62,668 ---------- ---------- ---------- Total .................................. $ 826,854 $ 631,095 $ 564,319 ========== ========== ========== Long-Lived Assets United States ............................ $ 616,472 $ 477,593 $ 479,753 Venezuela ................................ 84,856 37,001 62,931 Colombia ................................. 16,195 26,361 46,621 Other Foreign ............................ 100,881 132,650 101,910 ---------- ---------- ---------- Total .................................. $ 818,404 $ 673,605 $ 691,215 ========== ========== ==========
Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 14.9 percent, 15.2 percent, and 17.5 percent of the total consolidated revenues during the years ended September 30, 2001, 2000 and 1999, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.0 percent, 7.4 percent, and 12 percent of total consolidated revenues in the years ended September 30, 2001, 2000, and 1999, respectively. Collectively, the receivables from these customers were approximately $32.6 million and $17.4 million at September 30, 2001 and 2000, respectively. - -------------------------------------------------------------------------------- NOTE 15 SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES - -------------------------------------------------------------------------------- All of the Company's oil and gas producing activities are located in the United States. Results of Operations from Oil and Gas Producing Activities -
Years Ended September 30, 2001 2000 1999 - ------------------------------------------------------------ ---------- ---------- ---------- (in thousands) Revenues .............................................. $ 217,194 $ 157,583 $ 95,953 ---------- ---------- ---------- Production costs ...................................... 37,418 26,685 23,058 Exploration expense and valuation provisions .......... 46,093 30,832 22,992 Depreciation, depletion and amortization .............. 38,104 33,462 38,658 Income tax expense .................................... 34,986 23,447 3,437 ---------- ---------- ---------- Total cost and expenses .......................... 156,601 114,426 88,145 ---------- ---------- ---------- Results of operations (excluding corporate overhead and interest costs) .............................. $ 60,593 $ 43,157 $ 7,808 ========== ========== ==========
Capitalized Costs -
September 30, 2001 2000 - ----------------------------------------------------------------------- ---------- ---------- (in thousands) Proved properties ................................................ $ 486,772 $ 430,675 Unproved properties .............................................. 34,901 27,050 Total costs ................................................. 521,673 457,725 ---------- ---------- Less - Accumulated depreciation, depletion and amortization ...... 357,094 314,091 ---------- ---------- Net ......................................................... $ 164,579 $ 143,634 ========== ==========
Costs Incurred Relating to Oil and Gas Producing Activities -
Years Ended September 30, 2001 2000 1999 - -------------------------------------- ---------- ---------- ---------- (in thousands) Property acquisition: Proved ...................... $ 738 $ 105 $ 89 Unproved .................... 18,612 11,040 14,385 Exploration ..................... 44,166 43,833 22,292 Development ..................... 41,459 18,843 19,167 ---------- ---------- ---------- Total ....................... $ 104,975 $ 73,821 $ 55,933 ========== ========== ==========
32 Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) - Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. The following is an analysis of proved oil and gas reserves as estimated by Netherland, Sewell & Associates, Inc. at September 30, 2001 and 2000. Amounts at September 30, 1999 were estimated by the Company and reviewed by independent engineers.
OIL (Bbls) GAS (Mmcf) ---------- ---------- Proved reserves at September 30, 1998............................................ 4,761,313 251,626 Revisions of previous estimates.................................................. 570,126 11,771 Extensions, discoveries and other additions...................................... 151,829 22,491 Production....................................................................... (649,370) (44,240) Purchases of reserves-in-place................................................... -- 77 Sales of reserves-in-place....................................................... -- (2,105) --------- ------- Proved reserves at September 30, 1999............................................ 4,833,898 239,620 Revisions of previous estimates.................................................. 1,316,714 17,363 Extensions, discoveries and other additions...................................... 1,119,314 52,569 Production....................................................................... (880,304) (46,923) Purchases of reserves-in-place................................................... 1,502 242 Sales of reserves-in-place....................................................... (85,987) (373) --------- ------- Proved reserves at September 30, 2000............................................ 6,305,137 262,498 Revisions of previous estimates.................................................. (700,329) (17,018) Extensions, discoveries and other additions...................................... 1,144,709 12,748 Production....................................................................... (818,356) (42,387) Purchases of reserves-in-place................................................... 434 496 Sales of reserves-in-place....................................................... -- -- --------- ------- Proved reserves at September 30, 2001............................................ 5,931,595 216,337 ========= ======= Proved developed reserves at September 30, 1999 ........................................................... 4,828,071 229,765 ========= ======= September 30, 2000 ........................................................... 5,847,217 217,334 ========= ======= September 30, 2001 ........................................................... 4,865,569 198,103 ========= =======
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) - The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under Financial Accounting Standards Board Statement No. 69 "Disclosures About Oil and Gas Producing Activities". The Standardized Measure does not purport to present the fair market value of a company's proved oil and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into account in calculating the Standardized Measure. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and gas properties. Tax credits and permanent differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a ten percent annual discount rate to arrive at the Standardized Measure.
At September 30, 2001 2000 - ------------------------------------------------------------------ ----------- ----------- (in thousands) Future cash inflows .............................................. $ 467,886 $ 1,377,922 Future costs - Future production and development costs ...................... (174,703) (317,898) Future income tax expense .................................... (81,253) (331,672) ----------- ----------- Future net cash flows ............................................ 211,930 728,352 10% annual discount for estimated timing of cash flows ........... (67,891) (240,281) ----------- ----------- Standardized Measure of discounted future net cash flows ......... $ 144,039 $ (488,071) =========== ===========
33 Changes in Standardized Measure Relating to Proved Oil and Gas Reserves (Unaudited)
Years Ended September 30, 2001 2000 1999 - --------------------------------------------------------------- --------- --------- --------- (in thousands) Standardized Measure - Beginning of year ...................... $ 488,071 $ 232,618 $ 125,927 Increases (decreases) - Sales, net of production costs .............................. (179,776) (130,898) (72,895) Net change in sales prices, net of production costs ......... (400,679) 261,926 142,970 Discoveries and extensions, net of related future development and production costs ........................ 29,387 156,840 38,164 Changes in estimated future development costs ............... 10,667 (36,994) (11,095) Development costs incurred .................................. 17,311 13,587 16,558 Revisions of previous quantity estimates .................... (15,298) 57,730 17,713 Accretion of discount ....................................... 68,021 30,951 16,700 Net change in income taxes .................................. 160,776 (114,762) (40,671) Purchases of reserves-in-place .............................. 619 542 96 Sales of reserves-in-place .................................. -- (700) (1,390) Changes in production rates and other ....................... (35,060) 17,231 541 --------- --------- --------- Standardized Measure - End of year ............................ $(144,039 $ 488,071 $ 232,618 ========= ========= =========
NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts)
1st 2nd 3rd 4th 2001 Quarter Quarter Quarter Quarter ---- ------- ------- ------- ------- Revenues ............................. $192,550 $221,569 $217,222 $195,513 Gross profit ......................... 59,614 72,939 67,607 50,325 Net income ........................... 33,840 41,749 40,437 28,228 Basic net income per share ........... .68 .83 .80 .56 Diluted net income per share ......... .67 .82 .79 .56
1st 2nd 3rd 4th 2000 Quarter Quarter Quarter Quarter ---- ------- ------- ------- ------- Revenues ............................. $149,581 $151,848 $151,968 $177,698 Gross profit ......................... 37,852 36,256 32,605 44,704 Net income ........................... 20,461 19,273 18,557 24,009 Basic net income per share ........... .41 .39 .37 .48 Diluted net income per share ....... .41 .39 .37 .48
Gross profit represents total revenues less operating costs, depreciation, depletion and amortization, dry holes and abandonments, and taxes, other than income taxes. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding. Net income in the second quarter of 2001 includes an after-tax charge of $2.4 million ($0.05 per share, on a diluted basis) related to the write-down of producing properties in accordance with SFAS No. 121. Net income in the third quarter of 2001 includes an after-tax gain of approximately $1.9 million ($0.04 per share, on a diluted basis) related to a 1997 Kansas ad valorem assessment that was settled at less than the original liability. The after-tax gain increased natural gas revenues by approximately $.7 million and decreased interest expense by approximately $1.2 million. Net income in the fourth quarter of 2001 includes an after-tax charge of $2.8 million ($0.06 per share, on a diluted basis) related to the write-down of producing properties in accordance with SAFS No. 121. Net income in the first quarter of 2000 includes approximately $6.3 million ($0.13 per share, on a diluted basis) on gains related to a non-monetary dividend received and a gain on the conversion of shares of common stock of a Company investee pursuant to that investee being acquired. Net income in the fourth quarter of 2000 includes an after-tax charge of $2.5 million ($0.05 per share, on a diluted basis) related to the write-down of producing properties in accordance with SFAS No. 121. 34 REPORT OF INDEPENDENT AUDITORS HELMERICH & PAYNE, INC. The Board of Directors and Shareholders Helmerich & Payne, Inc. We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2001 and 2000, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2001 and 2000, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States. /s/ ERNST & YOUNG LLP Tulsa, Oklahoma November 19, 2001 STOCK PRICE INFORMATION
Closing Market Price Per Share ------------------------------ 2001 2000 ---- ---- QUARTERS HIGH LOW HIGH LOW - -------- ---- --- ---- --- First............................... $ 44.19 $ 28.94 $ 27.44 $ 19.13 Second.............................. 58.51 39.63 31.00 20.00 Third............................... 51.23 30.82 37.75 29.06 Fourth.............................. 32.77 23.74 38.31 30.06
DIVIDEND INFORMATION
Paid Per Share Total Payment -------------- ------------- 2001 2000 2001 2000 ---- ---- ---- ---- QUARTERS - -------- First............................... $.075 $.070 $3,748,896 $3,474,612 Second............................... .075 .070 3,776,612 3,475,623 Third............................... .075 .070 3,796,489 3,484,189 Fourth............................... .075 .075 3,765,488 3,740,863
STOCKHOLDERS' MEETING The annual meeting of stockholders will be held on March 6, 2002. A formal notice of the meeting, together with a proxy statement and form of proxy, will be mailed to shareholders on or about January 25, 2002. STOCK EXCHANGE LISTING Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol "HP." The newspaper abbreviation most commonly used for financial reporting is "HelmP." Options on the Company's stock are also traded on the New York Stock Exchange. STOCK TRANSFER AGENT AND REGISTRAR As of December 14, 2001, there were 1,090 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent's records. Our Transfer Agent is responsible for our shareholder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with The Transfer Agent at the following address: UMB Bank Security Transfer Division 928 Grand Blvd., 13th Floor Kansas City, MO 64106 Telephone: (800) 884-4225 (816) 860-5000 FORM 10-K The Company's Annual Report on Form 10-K, which has been submitted to the Securities and Exchange Commission, is available free of charge upon written request. ADDITIONAL INFORMATION In a continuing effort to find timely and cost effective communications solutions to serve the needs of our shareholders, we are discontinuing the printing and distribution of our traditional quarterly shareholder reports. Effective the first quarter ending December 31, 2001, quarterly reports on Form 10-Q, earnings releases and financial statements will be made available on the investor relations section of the Company's Web site. Quarterly reports on Form 10-Q, earnings releases and financial statements will also be available free of charge upon written request. DIRECT INQUIRIES TO: Investor Relations Helmerich & Payne, Inc. Utica at Twenty-First Tulsa, Oklahoma 74114 Telephone: (918) 742-5531 Internet Address: http://www.hpinc.com 35 ELEVEN-YEAR FINANCIAL REVIEW HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999 - --------------------------------------------------------------------------- -------- --------- --------- REVENUES AND INCOME*(2) Contract Drilling Revenues....................................... 484,927 349,992 394,715 Crude Oil Sales.................................................. 22,815 24,601 9,479 Natural Gas Sales................................................ 192,962 131,056 81,533 Gas Marketing Revenues........................................... 99,140 78,921 54,263 Real Estate Revenues............................................. 9,066 8,991 8,663 Dividend Income.................................................. 3,909 14,482 3,569 Other Revenues................................................... 14,035 23,052 12,097 Total Revenues+.................................................. 826,854 631,095 564,319 Net Cash Provided by Continuing Operations+...................... 278,856 201,836 158,694 Income from Continuing Operations................................ 144,254 82,300 42,788 Net Income....................................................... 144,254 82,300 42,788 --------- --------- --------- PER SHARE DATA Income from Continuing Operations(1): Basic........................................................ 2.88 1.66 .87 Diluted...................................................... 2.84 1.64 .86 Net Income(1): Basic........................................................ 2.88 1.66 .87 Diluted...................................................... 2.84 1.64 .86 Cash Dividends................................................... .30 .285 .28 Shares Outstanding*.............................................. 49,853 49,980 49,626 --------- --------- --------- FINANCIAL POSITION Net Working Capital*............................................. 210,191 186,250 88,720 Ratio of Current Assets to Current Liabilities................... 2.73 3.36 2.23 Investments*..................................................... 200,286 304,326 238,475 Total Assets*.................................................... 1,364,507 1,259,492 1,109,699 Long-Term Debt*.................................................. 50,000 50,000 50,000 Shareholders' Equity*............................................ 1,026,477 955,703 848,109 --------- --------- --------- CAPITAL EXPENDITURES* Contract Drilling Equipment...................................... 173,856 49,774 68,639 Wells and Equipment.............................................. 74,580 54,764 29,947 Real Estate...................................................... 1,144 2,880 1,435 Other Assets (includes undeveloped leases)....................... 28,904 24,514 22,930 Discontinued Operations.......................................... -- -- -- Total Capital Outlays............................................ 278,484 131,932 122,951 --------- --------- --------- PROPERTY, PLANT AND EQUIPMENT AT COST* Contract Drilling Equipment...................................... 1,028,015 891,749 881,269 Producing Properties............................................. 486,772 430,674 421,552 Undeveloped Leases............................................... 34,901 27,050 25,337 Real Estate...................................................... 50,579 50,649 49,065 Other............................................................ 86,300 80,268 71,139 Discontinued Operations.......................................... -- -- -- Total Property, Plant and Equipment.............................. 1,686,567 1,480,390 1,448,362 --------- --------- ---------
* 000's omitted. + Chemical operations were sold August 30, 1996. Prior year amounts have been restated to exclude discontinued operations. (1) Includes $13.6 million ($.28 per share, on a diluted basis) effect of impairment charge for adoption of SFAS No. 121 in 1995 and cumulative effect of change in accounting for income taxes of $4,000,000 ($.08 per share, on a diluted basis) in 1994. (2) See Note 14 for segment presentation of revenues. 36
Years Ended September 30, 1998 1997 1996 1995 - --------------------------------------------------------------------------- --------- --------- --------- --------- REVENUES AND INCOME*(2) Contract Drilling Revenues....................................... 427,713 315,327 244,338 203,325 Crude Oil Sales.................................................. 10,333 20,475 15,378 13,227 Natural Gas Sales................................................ 87,646 87,737 60,500 33,851 Gas Marketing Revenues........................................... 52,469 66,306 57,817 34,729 Real Estate Revenues............................................. 8,587 8,224 8,076 7,560 Dividend Income.................................................. 4,117 5,268 3,650 3,389 Other Revenues................................................... 45,775 14,522 3,496 10,640 Total Revenues+.................................................. 636,640 517,859 393,255 306,721 Net Cash Provided by Continuing Operations+...................... 113,533 165,568 121,420 84,010 Income from Continuing Operations................................ 101,154 84,186 45,426 5,788 Net Income....................................................... 101,154 84,186 72,566 9,751 --------- --------- --------- --------- PER SHARE DATA Income from Continuing Operations(1): Basic........................................................ 2.03 1.69 .92 .12 Diluted...................................................... 2.00 1.67 .91 .12 Net Income(1): Basic........................................................ 2.03 1.69 1.47 .20 Diluted...................................................... 2.00 1.67 1.46 .20 Cash Dividends................................................... .275 .26 .2525 .25 Shares Outstanding*.............................................. 49,383 50,028 49,771 49,529 --------- --------- --------- --------- FINANCIAL POSITION Net Working Capital*............................................. 58,861 62,837 51,803 50,038 Ratio of Current Assets to Current Liabilities................... 1.47 1.66 1.83 1.74 Investments*..................................................... 200,400 323,510 229,809 156,908 Total Assets*.................................................... 1,090,430 1,033,595 821,914 707,061 Long-Term Debt*.................................................. 50,000 -- -- -- Shareholders' Equity*............................................ 793,148 780,580 645,970 562,435 --------- --------- --------- --------- CAPITAL EXPENDITURES* Contract Drilling Equipment...................................... 206,794 109,036 79,269 80,943 Wells and Equipment.............................................. 38,970 35,024 21,142 19,384 Real Estate...................................................... 854 1,095 752 873 Other Assets (includes undeveloped leases)....................... 19,681 16,022 7,003 9,717 Discontinued Operations.......................................... -- -- 1,581 859 Total Capital Outlays............................................ 266,299 161,177 109,747 111,776 --------- --------- --------- --------- PROPERTY, PLANT AND EQUIPMENT AT COST* Contract Drilling Equipment...................................... 829,217 643,619 568,110 501,682 Producing Properties............................................. 414,770 395,812 392,562 384,755 Undeveloped Leases............................................... 20,977 14,109 9,242 8,051 Real Estate...................................................... 48,451 47,682 46,970 46,642 Other............................................................ 65,120 59,659 53,547 55,655 Discontinued Operations.......................................... -- -- -- 13,937 Total Property, Plant and Equipment.............................. 1,378,535 1,160,881 1,070,431 1,010,722 --------- --------- --------- --------- Years Ended September 30, 1994 1993 1992 1991 - --------------------------------------------------------------------------- --------- --------- --------- --------- REVENUES AND INCOME*(2) Contract Drilling Revenues....................................... 182,781 149,661 112,833 105,364 Crude Oil Sales.................................................. 13,161 15,392 16,369 17,374 Natural Gas Sales................................................ 45,261 52,446 38,370 35,628 Gas Marketing Revenues........................................... 51,874 63,786 40,410 10,055 Real Estate Revenues............................................. 7,396 7,620 7,541 7,542 Dividend Income.................................................. 3,621 3,535 4,050 5,285 Other Revenues................................................... 6,058 8,283 6,646 20,020 Total Revenues+.................................................. 310,152 300,723 226,219 201,268 Net Cash Provided by Continuing Operations+...................... 74,463 72,493 60,414 50,006 Income from Continuing Operations................................ 17,108 22,158 8,973 19,608 Net Income....................................................... 24,971 24,550 10,849 21,241 --------- --------- --------- --------- PER SHARE DATA Income from Continuing Operations(1): Basic........................................................ .35 .46 .19 .41 Diluted...................................................... .35 .45 .19 .41 Net Income(1): Basic........................................................ .51 .51 .22 .44 Diluted...................................................... .51 .50 .22 .44 Cash Dividends................................................... .2425 .24 .2325 .23 Shares Outstanding*.............................................. 49,420 49,275 49,152 48,976 --------- --------- --------- --------- FINANCIAL POSITION Net Working Capital*............................................. 76,238 104,085 82,800 108,212 Ratio of Current Assets to Current Liabilities................... 2.63 3.24 3.31 4.19 Investments*..................................................... 87,414 84,945 87,780 96,471 Total Assets*.................................................... 621,689 610,504 585,504 575,168 Long-Term Debt*.................................................. -- 3,600 8,339 5,693 Shareholders' Equity*............................................ 524,334 508,927 493,286 491,133 --------- --------- --------- --------- CAPITAL EXPENDITURES* Contract Drilling Equipment...................................... 53,752 24,101 43,049 56,297 Wells and Equipment.............................................. 40,916 23,142 21,617 34,741 Real Estate...................................................... 902 436 690 2,104 Other Assets (includes undeveloped leases)....................... 9,695 5,901 16,984 6,793 Discontinued Operations.......................................... 618 629 158 2,594 Total Capital Outlays............................................ 105,883 54,209 82,498 102,529 --------- --------- --------- --------- PROPERTY, PLANT AND EQUIPMENT AT COST* Contract Drilling Equipment...................................... 444,432 418,004 404,155 370,494 Producing Properties............................................. 377,371 340,176 329,264 312,438 Undeveloped Leases............................................... 11,729 10,010 12,973 5,552 Real Estate...................................................... 47,827 47,502 47,286 46,671 Other............................................................ 48,612 45,085 43,153 36,423 Discontinued Operations.......................................... 13,131 12,545 11,962 11,838 Total Property, Plant and Equipment.............................. 943,102 873,322 848,793 783,416 --------- --------- --------- ---------
37 ELEVEN-YEAR OPERATING REVIEW ================================================================================ HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999 - ------------------------------------------------------- ---------- ---------- ---------- CONTRACT DRILLING Drilling Rigs, United States .................. 59 48 46 Drilling Rigs, International .................. 32 40 44 Contract Wells Drilled, United States ......... 346 335 242 Total Footage Drilled, United States* ......... 4,415 4,058 2,938 Average Depth per Well, United States ......... 12,761 12,115 12,142 Percentage Rig Utilization, United States ..... 97 87 75 Percentage Rig Utilization, International ..... 56 47 53 ---------- ---------- ---------- PETROLEUM EXPLORATION AND DEVELOPMENT Gross Wells Completed ......................... 123 81 49 Net Wells Completed ........................... 69.5 42.7 23.9 Net Dry Holes ................................. 17.0 9.1 7.1 ---------- ---------- ---------- PETROLEUM PRODUCTION Net Crude Oil and Natural Gas Liquids Produced (barrels daily) .................... 2,242 2,405 1,779 Net Oil Wells Owned-- Primary Recovery ........ 113 107.1 124 Net Oil Wells Owned-- Secondary Recovery ...... 55 55.5 54 Secondary Oil Recovery Projects ............... 4 3 5 Net Natural Gas Produced (thousands of cubic feet daily) ............. 116,128 128,204 121,206 Net Gas Wells Owned ........................... 493 453 439 ---------- ---------- ---------- REAL ESTATE MANAGEMENT Gross Leasable Area (square feet)* ............ 1,652 1,652 1,652 Percentage Occupancy .......................... 93 91 95 ---------- ---------- ---------- TOTAL NUMBER OF EMPLOYEES Helmerich & Payne, Inc. and Subsidiaries ...... 4,245 3,606 3,440 ---------- ---------- ----------
000's omitted. 38
Years Ended September 30, 1998 1997 1996 1995 1994 - ------------------------------------------------------- -------- -------- -------- -------- -------- CONTRACT DRILLING Drilling Rigs, United States .................. 46 38 41 41 47 Drilling Rigs, International .................. 44 39 36 35 29 Contract Wells Drilled, United States ......... 242 246 233 212 162 Total Footage Drilled, United States* ......... 2,938 2,753 2,499 1,933 1,842 Average Depth per Well, United States ......... 12,142 11,192 10,724 9,119 11,367 Percentage Rig Utilization, United States ..... 95 88 82 71 69 Percentage Rig Utilization, International ..... 88 91 85 84 88 -------- -------- -------- -------- -------- PETROLEUM EXPLORATION AND DEVELOPMENT Gross Wells Completed ......................... 62 100 63 59 44 Net Wells Completed ........................... 35.7 49.3 35.3 27.4 15 Net Dry Holes ................................. 4.2 9.6 7.3 5.9 1.7 -------- -------- -------- -------- -------- PETROLEUM PRODUCTION Net Crude Oil and Natural Gas Liquids Produced (barrels daily) .................... 1,921 2,700 2,212 2,214 2,431 Net Oil Wells Owned-- Primary Recovery ........ 124 133 176.9 186 202 Net Oil Wells Owned-- Secondary Recovery ...... 53 49 63.8 64 71 Secondary Oil Recovery Projects ............... 5 5 12 12 14 Net Natural Gas Produced (thousands of cubic feet daily) ............. 117,431 110,859 94,358 72,387 72,953 Net Gas Wells Owned ........................... 436 410 378 354 341 -------- -------- -------- -------- -------- REAL ESTATE MANAGEMENT Gross Leasable Area (square feet)* ............ 1,652 1,652 1,654 1,652 1,652 Percentage Occupancy .......................... 97 95 94 87 83 -------- -------- -------- -------- -------- TOTAL NUMBER OF EMPLOYEES Helmerich & Payne, Inc. and Subsidiaries ...... 3,340 3,627 3,309 3,245 2,787 -------- -------- -------- -------- -------- Years Ended September 30, 1993 1992 1991 - ------------------------------------------------------- -------- -------- -------- CONTRACT DRILLING Drilling Rigs, United States .................. 42 39 46 Drilling Rigs, International .................. 29 30 25 Contract Wells Drilled, United States ......... 128 100 106 Total Footage Drilled, United States* ......... 1,504 1,085 1,301 Average Depth per Well, United States ......... 11,746 10,853 12,274 Percentage Rig Utilization, United States ..... 53 42 47 Percentage Rig Utilization, International ..... 68 69 69 -------- -------- -------- PETROLEUM EXPLORATION AND DEVELOPMENT Gross Wells Completed ......................... 42 54 45 Net Wells Completed ........................... 15.9 17.8 20.2 Net Dry Holes ................................. 4.3 4.3 4.3 -------- -------- -------- PETROLEUM PRODUCTION Net Crude Oil and Natural Gas Liquids Produced (barrels daily) .................... 2,399 2,334 2,152 Net Oil Wells Owned-- Primary Recovery ........ 202 220 227 Net Oil Wells Owned-- Secondary Recovery ...... 71 74 55 Secondary Oil Recovery Projects ............... 14 14 12 Net Natural Gas Produced (thousands of cubic feet daily) ............. 78,023 75,470 66,617 Net Gas Wells Owned ........................... 307 289 278 -------- -------- -------- REAL ESTATE MANAGEMENT Gross Leasable Area (square feet)* ............ 1,656 1,656 1,664 Percentage Occupancy .......................... 86 87 86 -------- -------- -------- TOTAL NUMBER OF EMPLOYEES Helmerich & Payne, Inc. and Subsidiaries ...... 2,389 1,928 1,758 -------- -------- --------
39 DIRECTORS OFFICERS ================================================================================ W. H. HELMERICH, III W. H. HELMERICH, III Chairman of the Board Chairman of the Board Tulsa, Oklahoma HANS HELMERICH HANS HELMERICH President and Chief Executive Officer President and Chief Executive Officer Tulsa, Oklahoma GEORGE S. DOTSON Vice President, WILLIAM L. ARMSTRONG** President of Helmerich & Payne Chairman International Drilling Co. Transland Financial Services, Inc. Denver, Colorado DOUGLAS E. FEARS Vice President and GLENN A. COX* Chief Financial Officer President and Chief Operating Officer, Retired Phillips Petroleum Company STEVEN R. MACKEY Bartlesville, Oklahoma Vice President, Secretary, and General Counsel GEORGE S. DOTSON Vice President, STEVEN R. SHAW President of Helmerich & Payne Vice President, International Drilling Co. Exploration & Production Tulsa, Oklahoma L. F. ROONEY, III* Chief Executive Officer Manhattan Construction Company Tulsa, Oklahoma EDWARD B. RUST, JR.* Chairman and Chief Executive Officer State Farm Insurance Companies Bloomington, Illinois GEORGE A. SCHAEFER** Chairman and Chief Executive Officer, Retired Caterpillar Inc. Peoria, Illinois JOHN D. ZEGLIS** Chairman and Chief Executive Officer AT&T Wireless Services Basking Ridge, New Jersey - ---------- * Member, Audit Committee ** Member, Human Resources Committee
40 EX-21 4 d93048ex21.txt SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT Helmerich & Payne, Inc. Subsidiaries of Helmerich & Payne, Inc. Helmerich & Payne Properties, Inc. (Incorporated in Oklahoma) Utica Square Shopping Center, Inc. (Incorporated in Oklahoma) The Hardware Store of Utica Square, Inc. (Incorporated in Oklahoma) The Space Center, Inc. (Incorporated in Oklahoma) H&P DISC, Inc. (Incorporated in Oklahoma) Helmerich & Payne Coal Co. (Incorporated in Oklahoma) Helmerich & Payne Energy Services, Inc. (Incorporated in Oklahoma) Helmerich & Payne International Drilling Co. (Incorporated in Delaware) Subsidiaries of Utica Square Shopping Center, Inc. Fishercorp, Inc. (Incorporated in Oklahoma) Subsidiaries of Helmerich & Payne International Drilling Co. Helmerich & Payne (Africa) Drilling Co. (Incorporated in Cayman Islands, British West Indies) Helmerich & Payne Drilling (Bolivia) S.A. (Incorporated in Bolivia) Helmerich & Payne (Colombia) Drilling Co. (Incorporated in Oklahoma) Helmerich & Payne (Gabon) Drilling Co. (Incorporated in Cayman Islands, British West Indies) Helmerich & Payne (Argentina) Drilling Co. (Incorporated in Oklahoma) Helmerich & Payne (Peru) Drilling Co. (Incorporated in Oklahoma) Helmerich & Payne (Peru) Drilling Co., Sucursal del Peru, Lima (Lima Branch - Incorporated in Peru) Helmerich & Payne (Peru) Drilling Co., Sucursal del Peru (Iquitos Branch - Incorporated in Peru) Helmerich & Payne (Australia) Drilling Co. (Incorporated in Oklahoma) Helmerich & Payne del Ecuador, Inc. (Incorporated in Oklahoma) Helmerich & Payne de Venezuela, C.A. (Incorporated in Venezuela) Helmerich & Payne, C.A. (Incorporated in Venezuela) Helmerich & Payne Rasco, Inc. (Incorporated in Oklahoma) H&P Finco (Incorporated in Cayman Islands, British West Indies) H&P Invest Ltd. (Incorporated in Cayman Islands), British West Indies, doing business as H&P (Yemen) Drilling Co. Subsidiary of H&P Invest Ltd. Turrum Pty. Ltd. (Incorporated in Papua, New Guinea) EX-23.1 5 d93048ex23-1.txt CONSENT OF INDEPENDENT AUDITORS EXHIBIT 23.1 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in this Annual Report (Form 10-K) of Helmerich & Payne, Inc. of our report dated November 19, 2001, included in the 2001 Annual Report to Shareholders of Helmerich & Payne, Inc. We also consent to the incorporation by reference in the Registration Statements (Form S-8 Nos. 33-55239, 333-34939 and 333-63124) pertaining, respectively, to the 1990 Stock Option Plan, 1996 Stock Incentive Plan and 2000 Stock Incentive Plan of our report dated November 19, 2001, with respect to the consolidated financial statements of Helmerich & Payne, Inc. incorporated by reference in the Annual Report (Form 10-K) for the year ended September 30, 2001. ERNST & YOUNG LLP Tulsa, Oklahoma December 27, 2001 -----END PRIVACY-ENHANCED MESSAGE-----