Helmerich & Payne
Annual Report 2002

Plain-text annual report

Helmerich & Payne, Inc. During the final days of fiscal 2002, the Company concluded a transaction that merged its exploration, production, and gas-marketing divisions with Key Production Company, forming a significant new independent exploration and production company. H&P’s financial strength enabled it to look beyond a cash-generating transaction to something that was efficient and shareholder friendly. (cid:1) This transaction did not trigger taxation for H&P or its shareholders. (cid:1) H&P shareholders received a 65 percent ownership in Cimarex (NYSE-XEC). (cid:1) XEC emerged with almost 400 billion cubic feet equivalent of combined natural gas reserves at the end of 2001, and with a robust portfolio of exploration and development opportunities. (cid:1) H&P emerges from the transaction as a pure-play contract drilling company. F I N A N C I A L H I G H L I G H T S Years Ended September 30, 2002 2001 Revenues Net Income from Continuing Operations Net Income Diluted Earnings per Share from Continuing Operations Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets ( in thousands , except per share amounts) $ 510,928 $ 509,274 53,706 63,517 1.07 1.26 0.305 312,064 1,227,313 80,467 144,254 1.58 2.84 0.30 184,668 1,300,121 President’s Letter To the Co-owners of Helmerich & Payne, Inc. Corporate scandals and accounting fraud have battered investor confidence and abetted in a $7 trillion loss of market value since the spring of 2001. In a parade of infamy, CEOs of Enron, WorldCom, Global Crossing, and certain other large corporations compensated and conducted themselves with an absurd disregard for the future of their companies. After initially resisting corporate governance reforms, business leaders are now trying to get in front of efforts to restore investor trust. The challenge will be to achieve substance over mere form. That is where self-governance and old-fashioned integrity remain essential, where it’s meaningful to watch what we do and not just what we say, where embracing what is right instead of what is legal, and where, beyond new rules and regulations, management attitude and actions must seek to truly serve the shareholders. The creation of Cimarex at the end of the fiscal year hopefully provides a real world example in which our shareholders were well served. We distributed tax-free new shares that captured a stronger and more diversified oil and gas holding. Moreover, it demonstrated a long-term strength of this Company – an independent, experienced Board of Directors that has consistently provided important guidance, advice, and oversight. We selected an investment banker based not on previous research coverage, but on a focused expertise that fit our targeted strategy. Throughout the due diligence and approval process, our people and numbers were found to be both straightforward and competent by a myriad of industry participants, government regulators, lawyers, and bankers. I appreciate all the hard work and long hours a complex transaction like this requires. In the end, we accomplished what we said we would do, which is less extraordinary than simply the way we have attempted to conduct our business for 83 years. You will learn in this report about our exciting FlexRig™ construction program. Our success will depend on offering our customers more than a new and unique type of drilling rig. We are combining better equipment with the Company’s hard-earned reputation for providing principled and committed people. We believe holding ourselves to a high standard of integrity every day is less about compliance and more about fulfilling a promise. This is our pledge to you. Sincerely, Hans Helmerich December 10, 2002 H&P’s Growing Rig Fleet In the late 1970s, the Company centered its business strategy on quality, as opposed to a strategy that emphasized growth of the rig fleet. That mindset helped govern our expansion during what became a disastrous time for the industry, and it also marked the beginning of a shift in focus toward engineering and design. While the contract drilling industry was at its lowest ebb in the early 1980s, Helmerich & Payne International Drilling Co. was pursuing engineering- intensive work for offshore platform projects in the Gulf of Mexico and off the coast of California. The Company hired more engineers and built several offshore platform rigs throughout the ‘80s and the ‘90s, distinguishing itself by winning several prestigious contracts, including three rigs for Shell deep-water tension leg platforms. Today, the Company has approximately 90 engineers working throughout its operations and continues its push to foster new ideas, adding value to customers’ operations. At the close of the year, the Company owned a total of 111 rigs, 66 U.S. land rigs, 12 U.S. offshore platform rigs, and 33 international land rigs. The Company continues to assemble its new FlexRig™* in its own assembly facility in Houston, Texas. (See following story.) The FlexRig3 construction project is scheduled for completion in July 2003, at which time the Company’s rig fleet will have grown from 96 rigs at the end of 2001, to 128, a 33 percent increase. The FlexRig3 represents an unprecedented offering to drilling customers. Equipped with the latest technology that delivers significant improvements in safety and efficiency, the Company’s new FlexRigs have average utilizations in the 95-100 percent range, compared to industry averages of 60-65 percent over the past year. The reason? Customer satisfaction with the FlexRig’s ability to deliver value in the form of lower total well costs, higher productivity, and safer, more trouble-free operations. O U T L O O K The past year and a half has been volatile for the industry as well as the economy as a whole. The health of the U.S. drilling market continues to be tied to the price of natural gas. Pricing trends over the past year appear to confirm a tightening in natural gas supplies, which should equate to higher levels of drilling activity in the coming year. The Company has international operations in Ecuador, Venezuela, Colombia, Bolivia, Argentina, and Equatorial Guinea, West Africa. With the exception of Ecuador, South American activity has been down over the past two years, and crude oil prices have become a major factor along with the political climate of each particular country. The Company remains confident that there is considerable value in maintaining its long-standing presence in South America and believes that the region’s rich resource base will eventually spawn promising opportunities, including the possibility of introducing the FlexRig into this market. Additionally, efforts have increased to establish operations in other areas of the world. *Referred to here and after as FlexRig H&P FlexRig A N EW G E N E R AT I O N O F L A N D R I G The most interesting development in land drilling during the past two decades has been the conception, design, and construction of a new generation of land rigs known as H&P FlexRigs. Twenty-six FlexRigs have been con- structed since 1998, and 17 more are in progress, the last of which is scheduled for delivery in July 2003. Customer demand in the form of high activity and rates/margins confirms FlexRig value. W H Y B U I L D N E W R I G S ? were once again After the collapse of the land drilling industry in faced with the 1982, a number of contractors emerged and, by decision of whether the late 1980s, consolidated a significant portion to build new or of the remaining fleet. Instead of playing a major buy existing rigs, role as a consolidator, H&P chose to upgrade many now almost its existing land rig fleet and build new, fit-for- 25 years old. purpose offshore platform rigs. We believed our Once again, we future would be best served by an approach that believed our future The driller controls the FlexRig’s operation from a controlled climate cabin using touch screens and joystick controls. would incorporate the Company’s engineering would be best served by building new, more and design strengths. Rather than merely productive rigs. owning a large fleet of vintage 1980 land rigs, H&P pursued a strategy to build improved, more W H AT T O B U I L D ? productive rigs. By the mid-1990s, we completed Although H&P had an historic bias for deep improvements on our existing land rig fleet and drilling, our own investigation into U.S. land 62% of Total U.S. Rigs Drilling 1983-2002 >20,000' 17,501-20,000' 15,001-17,500' 10,001-15,000' 0-10,000' 29% 5% 3% 1% 1983 1986 1989 1992 of Total 2002 1995 1998 42% 45% 6% 4% 3% 2001 Reviewing the depths of wells drilled at any time during the past 20 years indicates growth in the 8-18,000’ segment. rig activity indicated that the 8,000’-18,000’ market segment was the largest and had the most growth potential – not the deep market of over 20,000’. Our experiences with six “highly H O W T O A D D VA L U E 1. Take lessons from the past and design safety into the new rig. 2. Review and improve work processes and rig layout to reduce the critical path and make the tasks friendlier to employees. 3. Design a rig that can move faster between well locations. 4. Implement new technology and design ideas, like H&P’s patented round mud tank system. 5. Link all operations through a dedicated, satellite-based wide area network. mobile” rigs that H&P purchased in 1994 C O U N T I N G T H E C O S T encouraged the Company’s Engineering Group Industry sources published articles in 1997 to develop a “better value” case for a new land estimating costs of approximately $11 million rig design using improved work processes and for a new 18,000’ capacity land rig. From new technical innovations. This new design H&P’s experience in upgrading and building new would offer customer flexibility by being economically competitive over a wide range of FlexRigs move an average 30 miles between wells in 2.5 days. Their mobility yields shorter well cycle times, greater productivity and more wells per year. rigs, we were confident that we could build new, improved rigs for considerably less. Our first six FlexRig1 rigs cost $6.7 million each in 1998, the next 12 FlexRig2 rigs cost $8 million each in 2001, and the 25 FlexRig3 rigs, offering significant upgrades in capability, presently cost $10.75 million each. We succeeded in delivering new, high-performance rigs operating tasks and well depths, ranging from in the field for a great deal less than the industry 8,000’-18,000’, hence the name FlexRig. thought possible. H&P FlexRig B U I L D I N G W I T H A L E A N A P P R O A C H . U N L I K E A N Y O T H E R R I G . F L E X R I G T R A I N I N G A N D O P E R AT I O N S Throughout the FlexRig projects, we acted as Operating the technologically advanced FlexRig3 our own general contractor. We purchased requires different skill sets and procedures. We major machinery and electrical components and assembled them in our facilities. H&P have created a FlexRig3 specific program to screen, has been even more ambitious in the FlexRig3 hire, train, and mold a mix of project. We designed and contracted construction of the major structures, organized our assembly new and present employees into 25 rig crews of 25 men facility along LEAN manufacturing techniques, each. Outstanding safety, field performance, and used outside certification authorities to and crew retention have review and certify our processes. As a result, confirmed the value of the we have designed, built, tested, and fielded a FlexRig3 training program. highly capable rig at a price that cannot be matched. H&P’s satellite-based Wide Area Network (WAN) has been invaluable in supporting field operations of the FlexRigs. The linkage between rigs, suppliers, and H&P tech- Our instructors and crews use a unique training aid to develop top drive skills. nicians and operations supervisors means shared learning and more timely assistance and prob- lem solving. The WAN frequently provides the means of adjusting software without the presence of a technician. LEAN manufacturing techniques contribute to managing costs and delivery schedule. W E I G H I N G T H E O U T C O M E The FlexRig programs have been unqualified successes. Already an industry leader in safety, H&P is reducing injuries further with the FlexRig. H&P The new hydraulic blowout preventer handling system shortens a well’s critical path and improves personnel safety. FlexRigs also increase productivity in the field with faster move times, better design, and the effective use of technology. We are reducing the critical path through our integrated top drive and hydraulic BOP handling system. The significant improvement in drilling performance by new rigs and crews has been recognized throughout the industry. The acid test for success is customer satisfaction, and the FlexRigs are operating at almost 100% utilization and at premium rates over market. The enlarged work area, open visibility, driller’s position, top drive, and hydraulic make-up and break-out tool significantly improve FlexRig safety and productivity. T H E C U S TO M E R R E S P O N S E Who is contracting the FlexRig? Our biggest customers are the super majors and large independents, who look beyond daily rig rates to overall project costs, safety, and reliable field operations. The Company believes it has a unique strategy that differentiates itself from the approach that is dominant in the contract drilling industry. Duplicating a FlexRig both in terms of H&P’s acquisition cost and performance value would require competitors to contend with barriers which the Company has already successfully passed: 1. The development of an engineering prowess in conceiving, building, and supporting new technology. 2. The commitment of an entire organization to overcome the considerable challenge of implementing new technology. 3. The achievement of a successful, sustained effort to attract, train, and retain competent personnel. Customer acceptance and satisfaction with the FlexRig and new technology will continue to be major drivers in the Company’s future strategy. Financial & Operating Review Years Ended September 30 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues Operating Costs Depreciation Operating Income Income from Investments Interest Expense General and Administrative Expense Income from Continuing Operations Net Income Diluted Earnings Per Common Share: Income from Continuing Operations Net Income 482,484 336,890 61,447 84,147 28,444 980 20,391 53,706 63,517 1.07 1.26 498,957 308,437 49,532 140,988 10,317 1,701 16,627 80,467 144,254 1.58 2.84 †All data excludes discontinued operations except net income. SUMMARY FINANCIAL DATA* Cash** Working Capital** Investments Plant, Property, and Equipment, Net** Total Assets Long-term Debt Shareholders’ Equity Capital Expenditures** *$000’s omitted, except per share data. ** Excludes discontinued operations. RIG FLEET SUMMARY Drilling Rigs - United States Land - Conventional United States Land - FlexRigs United States Offshore Platform International Total Rig Fleet Rig Utilization Percentage - United States Land - Conventional United States Land - FlexRigs United States Land - All Rigs United States Offshore Platform International 46,883 105,852 146,855 897,445 1,227,313 100,000 895,170 312,064 128,826 223,980 200,286 650,051 1,300,121 50,000 1,026,477 184,668 40 26 12 33 111 78 96 84 83 51 36 13 10 37 96 96 100 97 98 56 360,632 234,132 77,317 49,183 31,510 2,730 13,612 36,470 82,300 .73 1.64 107,632 179,884 304,326 526,723 1,200,854 50,000 955,703 65,820 32 6 10 40 88 82 99 85 94 47 405,350 272,683 70,092 62,575 7,377 5,389 15,603 32,115 42,788 439,842 291,179 58,187 90,476 44,363 336 13,231 80,790 101,154 325,895 206,596 48,291 71,008 11,437 34 10,538 48,801 84,186 252,323 167,789 39,592 44,942 5,782 678 10,251 25,844 72,566 212,588 146,207 37,364 29,017 10,846 407 9,899 18,464 9,751 193,076 138,449 31,038 23,589 6,303 385 9,972 13,216 24,971 158,020 109,786 29,397 18,837 9,050 925 7,558 8,978 24,550 121,977 83,931 28,496 9,550 9,202 632 7,741 1,363 10,849 .65 .86 1.60 2.00 .97 1.67 .52 1.46 .38 .20 .27 .51 .18 .50 .03 .22 21,758 82,893 238,475 553,769 1,073,465 50,000 848,109 78,357 24,476 49,179 200,400 548,555 1,053,200 50,000 793,148 217,597 27,963 65,802 323,510 392,489 987,432 — 780,580 114,626 16,892 48,128 229,809 329,377 786,351 — 645,970 83,411 19,543 50,038 156,908 286,678 707,061 — 562,435 89,709 29,447 76,238 87,414 235,067 624,827 — 524,334 59,379 61,656 104,085 84,945 209,877 610,935 3,600 508,927 27,823 37,586 82,800 87,780 212,941 585,504 8,339 493,286 51,525 34 6 10 39 89 68 79 69 95 53 30 6 10 44 90 94 100 94 99 88 29 — 9 39 77 99 — 99 63 91 30 — 11 36 77 88 — 88 70 85 30 — 11 35 76 73 — 73 66 84 36 — 11 29 76 66 — 66 79 88 31 — 11 29 71 48 — 48 70 68 30 — 9 30 69 40 — 40 49 69 Helmerich & Payne, Inc. FORM 10-K, 2002 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, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 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 incorpo- rated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x] At December 13, 2002, the aggregate market value of the voting stock held by non-affiliates was $1,412,972,260. Number of shares of common stock outstanding at December 13, 2002: 50,013,769. D O C U M E N T S I N C O R P O R AT E D B Y R E F E R E N C E Certain portions of the following documents have been incorporated by reference into this Form 10-K as indicated: Documents (1) Annual Report to Stockholders for the fiscal year ended September 30, 2002 10-K Parts Parts I, II, and IV (2) Proxy Statement for Annual Meeting of Stockholders to be held March 5, 2003 Part III D I S C L O S U R E R E G A R D I N G F O R W A R D - L O O K I N G S T A T E M E N T S 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 THIS REPORT INCLUDING ITEM 1 OF PART 1. BUSINESS “REGULATIONS, HAZARDS AND RISKS”, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 23 THROUGH 39 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 INTER- NAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. PART I I T E M 1 . B U S I N E S S Helmerich & Payne, Inc. (the “Company”), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. The Company is primarily engaged in contract drilling of oil and gas wells for others. The contract drilling business accounts for the major portion of its operating revenues. The Company is also engaged in the ownership, development, and operation of commercial real estate. The Company is organized into two separate autonomous operating entities being contract drilling and real estate. Both businesses operate independently of the other. Both the contract drilling and real estate businesses are conducted 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. The Company’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 Company has also operated during fiscal 2002 in six international locations: Venezuela, Ecuador, Colombia, Argentina, Bolivia and Equatorial Guinea. The Company’s real estate investments are located in Tulsa, Oklahoma, where the Company has its executive offices. Prior to October 1, 2002, the Company was engaged in the exploration, production and sale of crude oil and natural gas business (“exploration and production business”). During fiscal 2002, the Company transferred assets and liabilities of the exploration and production business to its wholly-owned subsidiary, Cimarex Energy Co. On September 30, 2002, the Company distributed the common stock of Cimarex Energy Co. to the Company’s stockholders and completed a merger of Key Production Company, Inc. with a subsidiary of Cimarex Energy Co. See pages 5 through 6 of this report for a more detailed discussion of the spin-off and merger. C O N T R A C T D R I L L I N G The Company 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 Company 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 Company operates certain rigs which are transportable by helicopter. In the United States, the Company draws its customers primarily from the major oil companies and the larger independents. In South America, the Company’s current customers include the Venezuelan state petroleum company and major international oil companies. In fiscal 2002, the Company received approximately 70% of its consolidated revenues from the Company’s ten largest contract drilling customers. BP plc, Shell Oil Company and ExxonMobil Corporation, including their affiliates, (respectively, “BP plc”, “Shell Oil Company” and “ExxonMobil Corporation”) are the Company’s three largest contract drilling customers. The Company performs drilling services for BP plc, Shell Oil Company and ExxonMobil Corporation on a world-wide basis. Revenues from drilling services performed for BP plc, Shell Oil Company and ExxonMobil Corporation in fiscal 2002 accounted for approximately 16%, 15% and 12%, respectively, of the Company’s consolidated revenues from continuing operations for the same period. While the Company believes that its relationship with all of these customers is good, the loss of BP plc, Shell Oil Company and ExxonMobil Corporation or a loss of one or more of its larger customers would have a material adverse effect on the drilling subsidiary and the Company. The Company provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided so that the Company’s customers may explore for and develop oil and gas from onshore areas and from fixed platforms, tension leg platforms and spars 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 1 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. 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. 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, the Company operates self-moving minimum space platform drilling rigs and drilling rigs to be used on tension leg platforms and spars. The minimum space rig is designed to be moved without the use of expensive derrick barges. The tension leg platforms and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms. The Company’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, the Company put to work a new generation of six highly mobile/depth flexible rigs (individually the “FlexRig”). The FlexRig has been able to significantly reduce average rig move times compared to similar depth rated traditional land rigs. 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 Company ordered 12 new FlexRigs at an approximate cost of between $7,500,000 and $8,250,000 each. The Company took delivery of 10 new FlexRigs through calendar 2001. During fiscal 2001, the Company ordered an additional 25 new FlexRigs at an approximate cost of $11,000,000 each. These new rigs, known as “FlexRig3”, are the next generation of FlexRigs which incorporate new drilling technology and new environmental and safety design. This new design includes integrated top drive, AC electric drive, hydraulic BOP handling system, hydraulic tubular make-up and break-out system, split crown and traveling blocks and an enlarged drill floor for the enabling of simultaneous crew activities. The Company took delivery of eight FlexRig3 rigs as of the end of September, 2002. The remaining FlexRig3 rigs are expected to be delivered by the end of fiscal 2003. The FlexRig3’s will be available for work in the Company’s domestic and international drilling operations. The Company’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 Company 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 Company has previously performed contracts on a combination “footage” and “daywork” basis, under which the Company 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 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 Company has previously accepted “turnkey” contracts under which the Company 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. The Company did not accept any “footage” or “turnkey” contracts during fiscal 2002. The Company believes that under current market conditions “footage” and “turnkey” contract rates do not adequately compensate contractors for the added risks. The duration of the Company’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 Company 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, Hazards and Risks on page 4 of this report. D O M E S T I C D R I L L I N G The Company believes it is a major land and offshore platform drilling contractor in the domestic market. At the end of September, 2002, the Company had 78 of its rigs (66 land rigs and 12 platform rigs) available for work in the United States and had management contracts for three customer-owned rigs. The 19 rig increase from fiscal 2001 to 2002 is due to the delivery of 13 new FlexRigs, transfer of four rigs from the Company’s international operations, and the construction of two self-moving platform rigs. While the Company commenced drilling operations in the Gulf of Mexico with two new self-moving platform rigs, the Company stacked five platform rigs during fiscal 2002. I N T E R N A T I O N A L D R I L L I N G The Company’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 Company, is one of the leading drilling contractors in Venezuela. Beginning in 1972, with the introduction of its first helicopter rig, the Company expanded into other Latin American countries. Venezuelan operations continue to be a significant part of the Company’s operations. At the end of fiscal 2002, the Company owned and operated 14 land drilling rigs in Venezuela with a utilization rate of approximately 41% for the fiscal year. The Company worked for the Venezuelan state petroleum company during fiscal 2002, and revenues from this work accounted for approximately 4.6% of the Company’s consolidated revenues from continuing operations during the fiscal year. In addition, the Company has performed contract drilling services in Venezuela for two independent oil companies during fiscal 2002. The Company’s rig utilization rate in Venezuela has increased from approximately 37% during fiscal 2001 to approximately 41% in fiscal 2002. Even though the Company is, at this time, unable to predict future fluctuations in its utilization rates during fiscal 2003, the Company believes that the prospects are good for returning at least five of its idle rigs back to work in Venezuela during fiscal 2003. During fiscal 2002, one rig was moved into Ecuador from the United States. At the end of fiscal 2002, the Company owned and operated eight rigs in Ecuador. The Company’s utilization rate was approximately 93% during fiscal 2002. Revenues generated by Ecuadorian drilling operations contributed approximately 8.89% of the Company’s consolidated revenue from continuing operations. The contracts are with large international oil companies. During fiscal 2002, the Company owned and operated three drilling rigs in Colombia. The Company’s utilization rate in Colombia was approximately 31% during fiscal 2002. The revenues generated by Colombian drilling operations contributed approximately 1.87% of the Company’s consolidated revenues in fiscal 2002 from continuing operations. The Company is not presently operating any rigs in Colombia, but expects to resume drilling operations with one rig in January, 2003. In addition to its operations in Venezuela, Ecuador and Colombia, the Company in fiscal 2002 owned and operated six rigs in Bolivia and two rigs in Argentina. However, at the end of fiscal 2002, only one rig was operating in Bolivia and no rigs were operating in Argentina. During fiscal 2002, the Company continued operations under a management contract for a customer-owned platform rig located offshore Equatorial Guinea. 2 3 C O M P E T I T I O N The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, rig availability, efficiency, condition of equipment, reputation, operating safety 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 Company has been successful in establishing long-term relationships with certain customers which have allowed the Company to secure drilling work even though the Company may not have been the lowest bidder for such work. The Company has continued to attempt to differentiate its services based upon its engineering design expertise, operational efficiency, safety and environmental awareness. This strategy is less effective when lower demand for drilling services intensifies price competition and makes it more difficult or impossible to compete on any other basis than price. R E G U L A T I O N S , H A Z A R D S A N D R I S K S The drilling operations of the Company are subject to the many hazards inherent in the business, including inclement weather, 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 Company’s offshore platform drilling operations are also subject to potentially greater environmental liability, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. The Company believes that it has adequate insurance coverage for comprehensive general liability, public liability, property damage, workers compensation and employer’s liability. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, the Company is generally indemnified under its drilling contracts from this risk. The majority of the Company’s insurance coverage has been purchased through fiscal 2003; however, rates and deductibles increased substantially for a number of coverages due to general hardening in the energy insurance market. In view of these present conditions, no assurance can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2003 or that insurance coverage will continue to be available at rates considered reasonable. The Company’s operations can be materially affected by low oil and gas prices. The Company believes that any significant reduction in oil and gas prices could result in a corresponding decline in demand for the Company’s services. Any prolonged reduction in demand for the Company’s services could have a material and adverse effect on the Company. International operations are subject to certain political, economic, and other uncertainties not encountered in domestic operations, including increased risks of terrorism, kidnapping of employees, 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 Company’s operations or on the ability of the Company to continue operations in certain areas. Because of the impact of local laws, the Company’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 Company holds only a minority interest, or pursuant to arrangements under which the Company conducts operations under contract to local entities. While the Company believes that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on the Company’s operations or revenues, there can be no assurance that the Company will in all cases be able to structure or restructure its operations to conform to local law (or the administration thereof) on terms acceptable to the Company. The Company further attempts to minimize the potential impact of such risks by operating in more than one geographical area. During fiscal 2002, approximately 27% of the Company’s consolidated revenues from continuing operations were generated from the international contract drilling business. Approximately 91% of the international revenues were from operations in South America and approximately 67% of South American revenues were from Venezuela and Ecuador. Based upon current information, the Company believes that exposure to potential losses from currency devaluation is minimal in Colombia, Ecuador and Bolivia. 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 January, 2002, Argentina suffered a 60% devaluation of the peso. The Argentine government required that all payments under all contracts were to be immediately converted to Argentine pesos and that contracting parties would share in the currency losses. The Company recorded a currency loss of US$1,200,000 in the first quarter of the fiscal year 2002 to recognize the loss of value in its accounts receivable. The Company has completed negotiations with its customers and has secured agreements that limit the portion of the accounts receivable that will be paid in pesos with the balance of such accounts receivable to be paid in U.S. dollars. Based upon such agreements, the Company does not expect significant Argentine currency losses in fiscal 2003. In Venezuela, approximately 60% of the Company’s invoice billings are in U.S. dollars and 40% are in the local currency, the bolivar. The Company is exposed to risks of currency devaluation in Venezuela as a result of bolivar receivable balances and necessary bolivar cash balances. From August of 2001 to August of 2002, there was a 92% devaluation of the bolivar. As a result, the Company experienced a US$4,393,000 devaluation loss. The Company is unable to predict future devaluation in Venezuela. In the event that fiscal 2003 activity levels are similar to fiscal 2002 and if a 25% to 100% devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately US$1,700,000 to US$4,200,000. Recent events in Venezuela have created greater governmental instability. In the event that labor strikes continue or turmoil increases, the Company could experience shortages in material and supplies necessary to operate some or all of its Venezuelan drilling rigs. 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 the Company’s loss of all or a portion of its assets and business in Venezuela. Many aspects of the Company’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 Company is indemnified under drilling contracts from liability arising from pollution, except in certain cases of surface pollution. However, the enforce- ability of indemnification provisions in foreign countries may be questionable. The Company 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 Company, 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. E X P L O R A T I O N A N D P R O D U C T I O N On February 23, 2002, the Company and Key Production Company, Inc. entered into an Agreement and Plan of Merger and related agreements, including a Distribution Agreement between the Company and Cimarex Energy Co. The agreements provided for the consolidation of the Company’s exploration and production business under 4 5 Cimarex Energy Co.; the distribution of Cimarex Energy Co. common stock to the Company’s stockholders; and the merger of Key Production Company, Inc. with a subsidiary of Cimarex Energy Co. 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. As a part of this transaction, Cimarex Energy Co. agreed to defend and indemnify the Company against all losses or liabilities arising out of or related to the exploration and production business that was transferred by the Company to Cimarex Energy Co. In July of 2002, the Company obtained a Private Letter Ruling from the Internal Revenue Service to the effect that the contribution and transfer of the assets and liabilities of the Company’s exploration and production business to Cimarex Energy Co. and the distribution by the Company of all the shares of Cimarex Energy Co. common stock to the holders of the Company’s common stock would generally be treated as a tax-free transaction for U.S. federal income tax purposes. On September 30, 2002, the Company’s distribution of Cimarex Energy Co. common stock and the subsequent merger of Key Production Company, Inc. was completed. Upon completion of the merger, approximately 65.25% of the Cimarex Energy Co. common stock on a diluted basis was held by former stockholders of the Company. Subsequent to this transaction, the Company and its subsidiaries will continue to own and operate the contract drilling and real estate businesses, and Cimarex Energy Co. will be a separate, publicly-traded company that will own and operate the exploration and production business. The Company does not own any common stock of Cimarex Energy Co. R E A L E S T A T E O P E R A T I O N S The Company’s real estate operations are conducted exclusively within the metropolitan area of Tulsa, Oklahoma. Its major holding is Utica Square Shopping Center, consisting of fourteen separate buildings, with parking and other common facilities covering an area of approximately 30 acres. These buildings provide approximately 405,709 square feet of net leasable retail sales and storage space (80% of which is currently leased) and approx- imately 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 Company’s real estate operations. Occupancy in the Shopping Center has decreased from 97% in fiscal 2001 to 80% in fiscal 2002 due to the closing of a large department store. In calendar 2003, the Company intends to renovate the vacated department store space containing approxi- mately 75,000 square feet and convert such space to multi-tenant specialty store use. In March of 2002, an eight-story medical office building containing approximately 76,000 square feet of net leasable space and located in Utica Square was demolished. The Company is currently redeveloping the site. The new development is expect- ed to include two new upscale restaurants and additional customer parking. At the end of the 2002 fiscal year, the Company owned 11 of a total of 73 units in The Yorktown, a 16-story lux- ury residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to Utica Square Shopping Center. Three of the Company’s units are currently leased. The Company 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 Company’s principal executive offices. The Company also owns and leases to third-parties 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 Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses. At the end of fiscal 2002, the Company owned approximately 235.2 acres in Southpark consisting of approxi- mately 225.1 acres of undeveloped real estate (net of the 2.87 acre sale and condemnation proceeding described below) 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 approximately 90,000 square feet and the other con- taining approximately 112,500 square feet. Present occupancy is 93%. The Company believes that a high quality In April of 2002, the Company sold approximately 2.87 acres of undeveloped land in Southpark for $437,325. The Company 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. This matter was settled in fiscal 2002 subject to the execution of a mutually acceptable journal entry of judgment. As a result of the settlement, the Company will be required to reimburse $275,000 of the $2,800,000 purchase price previously paid by ODOT. The Company 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 94% to 80% during fiscal 2002. The Company 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 2002, occupancy has increased from 93% to 96%. The Company 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 2002, occupancy has remained at 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 2002, occupancy has remained at 17%. C O M P E T I T I O N The Company 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. The Company’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 the Company and have more contemporary facilities. F I N A N C I A L Information relating to Revenue and Operating Profit by Business Segments may be found on pages 64 through 66 of this report. E M P L O Y E E S The Company had 2,872 employees within the United States (13 of which were part-time employees) and 803 employees in international operations as of September 30, 2002. 6 7 I T E M 2 . P R O P E R T I E S C O N T R A C T D R I L L I N G The following table sets forth certain information concerning the Company’s domestic drilling rigs as of September 30, 2002: Rig Designation Registrant’s Classification Optimum Working Depth in Feet 158 110 156 159 141 142 143 145 155 96 118 119 120 146 147 154 162 164 165 166 167 168 169 108 178 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth Medium Depth (FlexRig 1) Medium Depth (FlexRig 1) Medium Depth (FlexRig 1) Medium Depth (FlexRig 1) Medium Depth (FlexRig 1) Medium Depth (FlexRig 1) Medium Depth (platform) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 2) Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) 8 10,000 12,000 12,000 12,000 14,000 14,000 14,000 14,000 14,000 16,000 16,000 16,000 16,000 16,000 16,000 16,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 Present Location Oklahoma Texas Texas Wyoming Texas Texas Texas Texas Texas Oklahoma Texas Texas Texas Texas Texas Wyoming Texas Texas Texas Texas Oklahoma Texas Texas Texas Texas Wyoming Utah Texas Texas Texas Texas Texas Texas Texas Texas Oklahoma Texas Texas Texas Texas Rig Designation Registrant’s Classification Optimum Working Depth in Feet Present Location Texas Texas Texas Texas Louisiana Oklahoma Texas Louisiana Oklahoma Texas Oklahoma Louisiana Offshore Louisiana Offshore Louisiana Offshore Louisiana Texas Texas Texas Texas Texas Texas Texas Louisiana Texas Offshore Louisiana Louisiana Louisiana Louisiana Texas Texas Louisiana Texas Louisiana Louisiana Offshore Louisiana Offshore Louisiana Offshore Louisiana 18,000 18,000 18,000 18,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 26,000 26,000 26,000 26,000 26,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000+ Texas 214 215 216 217 79 80 89 91 92 94 98 122 203 205 206 97 99 137 149 170 191 192 72 73 100 105 106 107 125 134 136 157 161 163 201 202 204 139 Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) Medium Depth (FlexRig 3) Deep Deep Deep Deep (platform) Deep Deep Deep Deep Deep (platform) Deep (platform) Deep (platform) Deep Deep Deep Deep Deep (Heli Rig) Deep Deep Very Deep Very Deep Very Deep (platform) Very Deep (platform) Very Deep (platform) Very Deep (platform) Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep (platform) Very Deep (platform) Very Deep (platform) Super Deep 9 The following table sets forth information with respect to the utilization of the Company’s domestic drilling rigs for the The following table sets forth information with respect to the utilization of the Company’s international drilling rigs for the periods indicated: periods indicated: Years ended September 30, Number of rigs owned at end of period Average rig utilization rate during period*† 1998 44 88% 1999 39 53% 2000 40 47% 2001 37 56% 2002 33 51% * A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. † Does not include rigs returned to United States for major modifications and upgrades. R E A L E S T A T E O P E R A T I O N S See Item 1. BUSINESS, pages 6 through 7 of this report. S T O C K P O R T F O L I O Information required by this item regarding the stock portfolio held by the Company may be found on page 36 of this report under the caption, “Management’s Discussion and Analysis of Results of Operations and Financial Condition.” I T E M 3 . L E G A L P R O C E E D I N G S The Company is subject to various claims that arise in the ordinary course of its business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect the financial position, results of operations, or liquidity of the Company. The Company is not a party to, and none of its property is subject to, any material pending legal proceedings. I T E M 4 . S U B M I S S I O N O F M AT T E R S T O A V O T E O F S E C U R I T Y H O L D E R S None. Years ended September 30, Number of rigs owned at end of period Average rig utilization rate during period* 1998 46 95% 1999 50 75% 2000 48 87% 2001 59 97% 2002 78 83% *A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2002: Rig Designation Registrant’s Classification Optimum Working Depth in Feet 14 19 20 140 171 172 22 23 132 176 121 173 117 123 138 148 160 190 113 115 116 127 128 129 133 135 150 151 152 153 174 175 177 Workover/drilling Workover/drilling Workover/drilling Medium Depth Medium Depth Medium Depth Medium Depth (Heli Rig) Medium Depth (Heli Rig) Medium Depth Medium Depth Deep Deep Deep Deep Deep Deep Deep Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Very Deep Super Deep Super Deep Very Deep Very Deep Very Deep 6,000 6,000 6,000 10,000 16,000 16,000 18,000 18,000 18,000 18,000 20,000 20,000 26,000 26,000 26,000 26,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000+ 30,000+ 30,000 30,000 30,000 Present Location Venezuela Venezuela Venezuela Venezuela Bolivia Bolivia Ecuador Ecuador Ecuador Ecuador Ecuador Bolivia Ecuador Bolivia Ecuador Venezuela Venezuela Ecuador Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Colombia Colombia Venezuela Bolivia Colombia Venezuela Argentina Bolivia Argentina 10 11 E X E C U T I V E O F F I C E R S O F T H E C O M P A N Y The Company paid quarterly cash dividends during the past two years as shown in the following table: The following table sets forth the names and ages of the Company’s executive officers, together with all positions and offices held with the Company 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, 79 Chairman of the Board Director since 1949; Chairman of the Board since 1960 Douglas E. Fears, 53 Vice President and Chief Financial Officer since 1988 Hans Helmerich, 44 President and Chief Executive Officer Director since 1987; President and Chief Executive Officer since 1989 Steven R. Mackey, 51 Vice President, Secretary and General Counsel Secretary since 1990; Vice President and General Counsel since 1988 George S. Dotson, 61 Vice President Director since 1990; Vice President since 1977 and President and Chief Operating Officer of Helmerich & Payne International Drilling Co. since 1977 Gordon K. Helm, 49 Controller Chief Accounting Officer of the Company; Controller since December 10, 1993 PART II I T E M 5 . M A R K E T F O R T H E C O M P A N Y ’ S C O M M O N S T O C K A N D R E L A T E D S T O C K H O L D E R M A T T E R S The principal market on which the Company’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: Quarter First Second Third Fourth 2001 High Low $ 44.19 $ 28.94 58.51 51.23 32.77 39.63 30.82 23.74 2002 High Low $ 33.69 $ 25.13 41.31 42.91 37.82 28.05 34.15 29.83 Quarter First Second Third Fourth Paid per Share Fiscal 2001 $0.075 0.075 0.075 0.075 2002 $0.075 0.075 0.075 0.080 Total Payment Fiscal 2001 2002 $3,748,896 $3,738,220 3,776,612 3,796,489 3,765,488 3,739,680 3,743,587 3,999,597 The Company paid a cash dividend of $.080 per share on December 2, 2002, to stockholders of record on November 15, 2002. Payment of future dividends will depend on earnings and other factors. As of December 13, 2002, there were 1,001 record holders of the Company’s common stock as listed by the transfer agent’s records. I T E M 6 . S E L E C T E D F I N A N C I A L D A T A The following table summarizes selected financial information and should be read in conjunction with the Consolidated Financial Statements and the Notes thereto and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations contained at pages 23 through 39 of this report. On September 30, 2002, the Company spun off Cimarex Energy Co., as described on pages 5 and 6 of this report. The historical financial data for the business conducted by Cimarex Energy Co. for 2002 has been reported as discontinued operations. F I V E - Y E A R S U M M A R Y O F S E L E C T E D F I N A N C I A L D A T A Sales, operating, and other revenues $484,205 $412,727 $392,142 $509,274 $510,928 Income from continuing operations 80,790 32,115 36,470 80,467 53,706 1998 1999 2000 2001 2002 (in thousands) Income from continuing operations per common share: Basic Diluted Total assets Long-term debt 1.62 1.60 0.65 0.65 0.74 0.73 1.61 1.58 1.08 1.07 1,053,200 1,073,465 1,200,854 1,300,121 1,227,313 50,000 50,000 0.28 50,000 0.285 50,000 100,000 0.30 0.305 Cash dividends declared per common share 0.275 12 13 I T E M 7. M A N A G E M E N T ’ S D I S C U S S I O N & A N A LY S I S O F R E S U LT S O F I T E M 1 2 . S E C U R I T Y O W N E R S H I P O F C E R T A I N B E N E F I C I A L O W N E R S O P E R AT I O N S A N D F I N A N C I A L C O N D I T I O N A N D M A N A G E M E N T Information required by this item may be found on pages 23 through 39 of this report under the caption “Management’s Discussion & Analysis of Results of Operations and Financial Condition”. I T E M 7A. Q U A N T I T A T I V E A N D Q U A L I T A T I V E D I S C L O S U R E S A B O U T M A R K E T R I S K Information required by this item may be found on the following pages of this report under “Management’s Discussion & Analysis of Results of Operations and Financial Condition”, and in “Notes to Consolidated Financial Statements”: M A R K E T R I S K • Foreign Currency Exchange Rate Risk • Commodity Price Risk • Interest Rate Risk • Equity Price Risk P A G E 37 38 38-39 39 I T E M 8. F I N A N C I A L S T A T E M E N T S A N D S U P P L E M E N T A R Y D A T A Information required by this item may be found on pages 40 through 67 of this report. I T E M 9. C H A N G E S I N A N D D I S A G R E E M E N T S W I T H A C C O U N TA N T S O N A C C O U N T I N G A N D F I N A N C I A L D I S C L O S U R E None. PART III I T E M 1 0 . D I R E C T O R S A N D E X E C U T I V E O F F I C E R S O F T H E C O M P A N Y 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 Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2003, to be filed with the Commission not later than 120 days after September 30, 2002. I T E M 1 1 . E X E C U T I V E C O M P E N S A T I O N This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2003, to be filed with the Commission not later than 120 days after September 30, 2002. This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2003, to be filed with the Commission not later than 120 days after September 30, 2002. I T E M 1 3 . C E R T A I N R E L A T I O N S H I P S A N D R E L A T E D T R A N S A C T I O N S This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2003, to be filed with the Commission not later than 120 days after September 30, 2002. I T E M 1 4 . C O N T R O L S A N D P R O C E D U R E S a) Evaluation of disclosure controls and procedures. Within the 90 day period prior to the filing date of this Annual Report on Form 10-K, the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and opera- tion of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer believe that: • the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and • the Company’s disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to the Company’s management, and made known to the Company’s Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure. b) Changes in internal controls. There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect the Company’s internal controls subsequent to their evaluation, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses. 14 15 PART IV I T E M 1 5 . E X H I B I T S , F I N A N C I A L S TAT E M E N T S C H E D U L E S , A N D R E P O R T S O N F O R M 8 - K a) 1. Financial Statements: The following appear in this report at the pages indicated below and are incorporated herein by reference. Report of Independent Auditors Consolidated Statements of Income for the Years Ended September 30, 2002, 2001 and 2000 40 41 Consolidated Balance Sheets at September 30, 2002 and 2001 42-43 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2002, 2001 and 2000 Consolidated Statements of Cash Flows for the Years Ended September 30, 2002, 2001 and 2000 Notes to Consolidated Financial Statements 44 45 46-67 2. Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto. 3. Exhibits. The following documents are included as exhibits to this Form 10-K. Exhibits incorporated by reference herein are duly noted as such. Unless so noted, each exhibit is filed herewith. 2.1 Agreement and Plan of Merger, dated as of February 23, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. is incorporated herein by reference to Exhibit 2.1 to the Cimarex Energy Co. Registration Statement No. 333-87948 on Form S-4 filed May 9, 2002. 3.1 Restated Certificate of Incorporation and Amendment to Restated Certificate of Incorporation of the Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. 3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2002, SEC File No. 001-04221. 4.1 Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company’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 Company effective January 1, 1990, as amended is incorporated herein by reference to Exhibit 10.3 of the Company’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 Company’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 Company’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 Company’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 Company’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 the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. *10.7 Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. *10.8 Form of Restricted Stock Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Company’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 Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. *10.10 Form of Agreements for the 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 the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. 10.11 Distribution Agreement dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. is incorporated herein by reference to Exhibit 10.1 to the Cimarex Energy Co. Registration Statement No. 333-87948 on Form S-4 filed May 9, 2002. 10.12 Tax Sharing Agreement dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. is incorporated herein by reference to Exhibit 10.2 to the Cimarex Energy Co. Registration Statement No. 333-87948 on Form S-4 filed May 9, 2002. 10.13 Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. is incorporated herein by reference to Exhibit 10.3 to the Cimarex Energy Co. Registration Statement No. 333-87948 on Form S-4 filed May 9, 2002. 10.14 Form of Director Nonqualified Stock Option Agreement for the 2000 Helmerich & Payne, Inc. Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.15 Form of Change of Control Agreement for Helmerich & Payne, Inc. (E&P) is incorporated herein by refer- ence to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. *10.16 Form of Change of Control Agreement for Helmerich & Payne, Inc. (Non-E&P) is incorporated herein by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.17 Helmerich & Payne, Inc. E&P Severance Plan dated August 26, 2002. 16 17 10.18 Second Amendment to Credit Agreement, dated as of July 16, 2002, by and among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Bank One, Oklahoma, N.A. is incorporated herein by refer- ence to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.19 Credit Agreement, dated as of July 16, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc., the several lenders from time to time party thereto, and Bank of Oklahoma, National Association is incorporated herein by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.20 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies. 13. The Company’s Annual Report to Stockholders for fiscal 2002. 21. List of Subsidiaries of the Company. 23.1 Consent of Independent Auditors. *Compensatory Plan or Arrangement. (b) Report on Form 8-K The Company filed five reports on Form 8-K during the last quarter of fiscal 2002 as follows: (cid:1) Form 8-K dated July 24, 2002, and containing a Press Release with attached Unaudited Consolidated Condensed Balance Sheets, Consolidated Statements of Income and Financial Results - Lines of Business, announcing the Company’s third quarter 2002 earnings. (cid:1) Form 8-K dated August 16, 2002, disclosing the first closing of the Company’s intermediate term debt facility. (cid:1) Form 8-K dated September 5, 2002, containing a Press Release announcing the Registration Statement of Cimarex Energy Co. declared effective by the Securities and Exchange Commission and fiscal 2003 earnings guidance. (cid:1) Form 8-K dated September 20, 2002, containing a Press Release announcing that September 27, 2002 was established as the record date of the Company’s common stock entitled to receive the spin-off distribution of Cimarex Energy Co. common stock, and that September 30, 2002 was established as the payment date for the spin-off distribution. (cid:1) Form 8-K dated September 30, 2002, containing a Press Release announcing completion of the spin-off of Cimarex Energy Co. and the subsequent merger of Key Production Company, Inc. and a subsidiary of Cimarex Energy Co. S I G N A T U R E S Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized: HELMERICH & PAYNE, INC. /s/ Hans Helmerich By Hans Helmerich, President and Chief Executive Officer Date: December 23, 2002 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 Company and in the capacities and on the dates indicated: /s/ William L. Armstrong By William L. Armstrong, Director Date: December 23, 2002 /s/ George S. Dotson By George S. Dotson, Director Date: December 23, 2002 /s/ W.H. Helmerich, III By W. H. Helmerich, III, Director Date: December 23, 2002 /s/ Edward B. Rust, Jr. By Edward B. Rust, Jr., Director Date: December 23, 2002 /s/ John D. Zeglis By John D. Zeglis, Director Date: December 23, 2002 /s/ Gordon K. Helm By Gordon K. Helm, Controller (Principal Accounting Officer) Date: December 23, 2002 /s/ Glenn A. Cox By Glenn A. Cox, Director Date: December 23, 2002 /s/ Hans Helmerich By Hans Helmerich, Director and CEO Date: December 23, 2002 /s/ L. F. Rooney, III By L. F. Rooney, III, Director Date: December 23, 2002 /s/ George A. Schaefer By George A. Schaefer, Director Date: December 23, 2002 /s/ Douglas E. Fears By Douglas E. Fears, (Principal Financial Officer) Date: December 23, 2002 18 19 C E R T I F I C A T I O N I, Hans Helmerich, certify that: 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report; 4. The Company’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and have: a) b) c) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; evaluated the effectiveness of the Company’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The Company’s other certifying officers and I have disclosed, based on our most recent evaluation, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions): a) b) all significant deficiencies in the design or operation of internal controls which could adversely affect the Company’s ability to record, process, summarize and report financial data and have identified for the Company’s auditors any material weaknesses in internal controls; and any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls; and 6. The Company’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. C E R T I F I C A T I O N I, Douglas E. Fears, certify that: 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report; 4. The Company’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and have: a) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) c) evaluated the effectiveness of the Company’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The Company’s other certifying officers and I have disclosed, based on our most recent evaluation, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions): a) b) all significant deficiencies in the design or operation of internal controls which could adversely affect the Company’s ability to record, process, summarize and report financial data and have identified for the Company’s auditors any material weaknesses in internal controls; and any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls; and 6. The Company’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Hans Helmerich Hans Helmerich, Chief Executive Officer December 23, 2002 /s/ Douglas E. Fears Douglas E. Fears, Chief Financial Officer December 23, 2002 20 21 Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the Annual Report of Helmerich & Payne, Inc. (the "Company") on Form 10-K for the period ending September 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Hans Helmerich, as Chief Executive Officer of the Company, and Douglas E. Fears, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that: (1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Hans Helmerich Hans Helmerich Chief Executive Officer December 23, 2002 /s/ Douglas E. Fears Douglas E. Fears Chief Financial Officer December 23, 2002 Management’s Discussion & Analysis of Results of Operations and Financial Condition R I S K F A C T O R S A N D F O R WA R D - L O O K I N G S TAT E M E N T S 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. 22 23 S P I N - O F F A N D M E R G E R T R A N S A C T I O N S On September 30, 2002, Helmerich & Payne, Inc. completed its distribution of 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders and the subsequent merger of Key Production Company, Inc. into a subsidiary of Cimarex making Key a wholly-owned subsidiary of Cimarex. The Cimarex Energy Co. stock distribution was recorded as a dividend and resulted in a decrease to consolidated stockholders’ equity of approximately $152.2 million. As a result of this transaction, the Company and its subsidiaries will continue to own and operate the contract drilling and real estate business, and Cimarex Energy Co. will be a separate, publicly-traded company that will own and operate the exploration and production business. The Company does not own any common stock of Cimarex Energy Co. (See Note 2 of the Financial Statements for complete description of the transaction.) As a result of the transaction, the Company is reporting the results of its former Exploration and Production Division (Cimarex Energy Co.) as discontinued operations. R E S U LT S O F O P E R AT I O N S All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Helmerich & Payne, Inc.’s net income for 2002 was $63,517,000 ($1.26 per share) compared with net income of $144,254,000 ($2.84 per share), in 2001, and $82,300,000 ($1.64 per share) in 2000. Included in net income for each year reported was income from discontinued operations of $9,811,000 ($0.19 per share) for 2002, $63,787,000 ($1.26 per share) for 2001, and $45,830,000 ($0.91 per share) for 2000. Also included in the Company's net income, but not related to its operations, were after-tax gains from the sale of investment securities of $15,206,000 ($0.30 per share) in 2002, $691,000 ($0.01 per share) in 2001, and $8,152,000 ($0.16 per share) in 2000. 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 equity affiliates, which totaled $0.06 per share in 2002, $0.04 per share in 2001, and $0.06 in 2000. 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 $510,928,000 in 2002, $509,274,000 in 2001, and $392,142,000 in 2000. Revenues increased by less than 1 percent from 2001 to 2002. Revenues from domestic operations rose by approximately 1 percent, due to the increase in U.S. land rig revenue days recorded in 2002, as the Company continued to complete the construction of new rigs during the year. Total H&P U.S. land rigs available were 66 at the end of 2002, and 49 at the end of 2001. Land rig utilization was 84 percent during 2002 and 97 percent in 2001. Increased U.S. land rig revenues were partially offset by declines in U.S. platform rig revenues. Total platform rig revenue days fell 8 percent from 2001 to 2002 as rig utilization fell to 83 percent in 2002, compared with 98 percent in 2001. Revenues from international drilling operations declined by 11 percent as the Company’s rig utilization in South America fell from 56 percent in 2001 to 51 percent in 2002. 24 25 The 30 percent increase in revenues from 2000 to 2001 was due to a 55 percent increase in domestic revenues and a 13 percent increase in international revenues. Demand for drilling services increased dramatically in the U.S. during 2001, causing average revenue per day to improve by 58 percent from 2000 to 2001. During 2000, U.S. land rig utilization was 85 percent and U.S. platform rig utilization was 94 percent. International rig utilizations improved to 56 percent during 2001, compared with 47 percent during 2000. Revenues from investments were $28,444,000 in 2002, $10,317,000 in 2001, and $31,510,000 in 2000. Included in revenues were pre-tax gains from the sale of investment securities of $24,820,000 in 2002, $1,189,000 in 2001, and $13,295,000 in 2000. Interest income from short-term investments was $1,432,000 in 2002, $5,219,000 in 2001 and $3,733,000 in 2000. Interest income from short-term investments was higher in 2001 and 2000 because the Company’s cash and cash equivalent balances increased in each of these years and because of higher prevailing market short-term interest rates. Dividend income was $2,192,000 in 2002, $3,909,000 in 2001 and $14,482,000 in 2000. Dividend income was unusually high in 2000 because the Company recognized $10,706,000 of non-monetary dividends when three Company investees spun-off subsidiaries to their shareholders. Operating costs in 2002 were $336,890,000 or 70 percent of operating revenue, compared with $308,437,000 or 62 percent of operating income in 2001, and $234,132,000 or 65 percent of operating income in 2000. The operating cost percentage rose in 2002 due to lower revenue per rig day, higher direct rig operating cost, and additional costs associated with the addition of 16 rigs to the U.S. land fleet during the year. The lower operating cost percentage in 2001, compared to 2000 was the result of higher revenue per rig day during 2001. Depreciation expense was $61,447,000 in 2002, $49,532,000 in 2001, and $77,317,000 in 2000. Effective October 1, 2000, the Company changed the estimated useful life of its drilling equipment from 10 years to 15 years, resulting in lower annual depreciation expense of approximately $30 million in 2001. Depreciation expense rose significantly during 2002, due to the addition of 3 rigs in 2001 and 20 rigs in 2002. The Company anticipates depreciation expense to increase again next year as a full year of depreciation is incurred on rigs placed in service in 2002 and as new rigs are constructed and employed in the field. General and administrative expenses increased by approximately 22 percent from 2001 to 2002, and by 22 percent from 2000 to 2001. The most significant portion of the increases for both 2001 and 2002 were from employee benefits relating to medical insurance, 401(k) matching, and pension expenses. Employee salaries and bonuses also contributed to the increases, along with increases in property and casualty insurance. It is anticipated that general and administrative expenses for 2003 will be higher than in 2002, due mainly to higher pension expense. The value of pension plan assets has declined as a result of the recent decline in the stock market. The Company lowered the expected return and discount rate assumptions for calculation of accrued pension benefit costs. Additionally, the Company may consider reclassifying to general and administrative expense some costs that have been included in operating costs in prior years. Interest expense was $980,000 in 2002, $1,701,000 in 2001, and $2,730,000 in 26 27 2000. Although actual cash interest expense varied only slightly during the past three years, the variance in construction project activity during those periods resulted in more interest being capitalized during 2001 and 2002, thereby lowering the amount expensed. As mentioned later in this section, the increase in the total debt of the Company through the issuance of $200,000,000 of intermediate-term debt will result in a significant increase in interest expense during 2003. The provision for income taxes totaled $40,573,000 in 2002, $54,689,000 in 2001, and $31,102,000 in 2000. Effective income tax rates on income from continuing operations were 44 percent in 2002, 41 percent in 2001, and 48 percent in 2000. The increase in effective tax rate from 2001 to 2002 was a result of currency fluctuations, primarily in Venezuela, resulting in additional taxes for inflationary gains and monetary corrections in 2002. The significant reduction in effective rates from 2000 to 2001 was a result of lower taxes in Venezuela, as a result of monetary correction losses and a larger proportion of income in the Company’s U.S. operations where tax rates are lower than the average tax rates in the Company’s international operations. C O N T R A C T D R I L L I N G O P E R AT I N G P R O F I T Demand for contract drilling services increased significantly during 2001, after experiencing a lull in activity from 1998 to 2000. The significant improvement was particularly experienced in U.S. land rig drilling where high natural gas prices prevailed during 2001, thereby spurring the significant increase in rig activity, dayrates, and costs. During 2002 demand for drilling services declined, causing dayrates to soften. U.S. land rig utilizations fell to 84 percent in 2002, compared to 97 percent for 2001, while the Company’s U.S. offshore platform rig business realized utilizations averaging 94 percent in 2000, and 98 percent in 2001. During 2002, the Company completed construction on 2 new platform rigs that commenced operations during the Company’s third quarter, moving its total platform fleet to 12. However, demand for platform rig services waned during the year moving the average utilization in that sector to 83 percent and decreasing rig revenue days by 8 percent. Therefore, with demand for drilling services declining in the U.S. during 2002, without a similar drop in costs, the Company’s operating profit in its domestic operations fell to $69,181,000 in 2002, compared to $107,691,000 in 2001. Operating profit during 2000 for the U.S. sector was $35,808,000. Currently, 6 of the Company’s 12 platform rigs are active, and land rig dayrates are approximately the same as those achieved during the fourth quarter of 2002. Should these conditions continue during 2003, operating profit for U.S. operations will be lower than in 2002. After a significant improvement in activity and profitability during the late ‘90s, demand for drilling services in the Company’s international sector has declined significantly, with about half of the rigs working in South America over the last two years compared with the number of rigs employed during the 1996 to 1999 time frame. As a result, operating profits for international operations have declined to $13,128,000 in 2002 from $28,475,000 in 2001. Operating profit was $9,753,000 in 2000. Utilizations were 51 percent in 2002, 56 percent in 2001, and 47 percent in 2000. 28 29 International operating profit declined from 2001 to 2002 due to lower rig utilization and higher devaluation losses. International operating profits improved during 2001 compared to 2000 mainly due to lower depreciation expenses resulting from a change in the estimated useful life in the Company’s drilling equipment as discussed below. The impact of the change added approximately $15 million to international operating profit in 2001, compared with 2000. Over the past three years, rig activity levels have generally improved in Ecuador where the Company has grown from 3 rigs in 1999 to 8 rigs by the end of 2002. Overall utilization in that country averaged 93 percent during 2002. Conversely, the rig count and utilization have declined dramatically in Colombia where the Company operated 10 rigs in 1999, but declined to 3 rigs by 2002. Overall utilization for 2002 in Colombia was 31 percent. In one of the Company’s main international operations, Venezuela, the total number of Company rigs has declined from 22 in 1999 to 14 in 2002. Average utilization during 2002 in Venezuela was 41 percent. The remainder of the Company’s rigs located in South America are in Bolivia (6 rigs), where utilization during 2002 was 30 percent, and Argentina (2 rigs), where average utilization was 59 percent. Although activity is expected to improve slightly in Venezuela during 2003, the Company does not expect international operating profit to improve substantially during the year. During 2002, the Company experienced devaluation losses totaling $1,200,000 in Argentina and $4,393,000 in Venezuela. Previous to this year devaluation losses in Venezuela totaled $796,000 in 2001 and $687,000 in 2000. During 2002, Argentina experienced a dramatic economic collapse. As a result, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos. The $1,200,000 loss recorded by the Company as of September 30, 2002 is an estimation of the losses it will experience after all current receivables are collected. The Company has completed negotiations with customers and has secured agreements that limit the portion of the accounts receivable that will be paid in pesos, with the balance of such accounts receivable to be paid in U.S. dollars. Based upon such agreements, the Company does not expect significant Argentine currency losses in fiscal 2003. In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 percent are in bolivars, the local currency. As a result, the Company is exposed to risk of currency devaluation in Venezuela because of bolivar denominated receivables. The Company anticipates additional devaluation losses in Venezuela during 2003, but it is unable to predict the extent of the devaluation. If 2003 rig activity levels are similar to 2002, and if a 25 percent to 100 percent devaluation would occur, the Company could experience potential devaluation losses ranging from approximately $1,700,000 to $4,200,000. R E A L E S TAT E S E G M E N T Revenues totaled $8,525,000 for 2002, $11,018,000 for 2001, and $8,999,000 for 2000. Operating profit was $5,064,000 for 2002, $6,315,000 for 2001, and $5,346,000 in 2000. The increase in revenues and operating profit in 2001 was due to the sale of a small parcel of raw land. Revenues and operating profit for 2002 were down due to slight reductions in occupancy rates for both retail and industrial properties. No material changes are anticipated in the Real Estate Division in 2003. 30 31 C R I T I C A L A C C O U N T I N G P O L I C I E S The Company’s consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. The following is a discussion of the critical accounting policies related to property, plant and equipment, impairments, self-insurance accruals, and revenue recognition. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements. Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts, and any gains or losses are recorded in our results of operations. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated undiscounted cash flows, expected to result from the use of the asset and its eventual disposition, are less than its carrying amount. Any impairment loss recognized represents the excess of the asset's carrying value as compared to its estimated fair value, which is determined based on the present value of estimated cash flows from the asset, appraisals or sales prices of comparable assets. There were no long-lived asset impairment losses in the Company’s continuing operations during the years ended September 30, 2002, 2001, and 2000. However, should industry market conditions deteriorate from those existing currently, impairment losses could be recorded. All of our drilling rigs are transportable and are therefore not limited to one area or country. Drilling rigs can be moved from countries where demand is low to countries experiencing high demand for drilling services. When making determinations of location for drilling rigs, the Company considers both long and short- term views of demand and other reasonable business considerations. The Company is self-insured or maintains high deductibles for certain losses relating to worker’s compensation, general, product, and auto liabilities. Generally, deductibles are $2 million per occurrence on claims that fall under these coverages. Insurance is also purchased on rig properties, and generally, deductibles are $1 million per occurrence. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred, and using the Company’s historical loss experience and estimation methods that are believed to be reliable and acceptable in the insurance industry. Revenues and costs on daywork contracts are recognized daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts 32 33 are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. L I Q U I D I T Y A N D C A P I TA L R E S O U R C E S The Company’s capital spending for continuing operations was $312,064,000 in 2002, $184,668,000 in 2001, and $65,820,000 in 2000. Net cash provided from operating activities for those same time periods were $151,774,000 in 2002, $127,435,000 in 2001, and $97,894,000 in 2000. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $47,146,000 in 2002, $24,438,000 in 2001, and $12,569,000 in 2000. During 2000, the Company announced a program (FlexRig2 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 7 of those 12 rigs. Additionally, the Company announced in 2001 that it would embark on another construction project (FlexRig3 program) to build an additional 25 FlexRigs at an approximate cost of $11.0 million each. During 2002, the Company completed the remaining 5 rigs in the FlexRig2 program and the first 8 rigs in the FlexRig3 program. The Company intends to complete the remaining 17 rigs of that program by July 2003. The Company expects to fund its 2003 capital spending of approximately $195,000,000 with internally generated cash flow and recently arranged debt financing. In August 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities from 5 to 12 years and a weighted average interest rate of 6.31 percent. Funding of the notes occurred on August 15, 2002 and October 15, 2002 in equal amounts of $100 million. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. Proceeds from the intermediate-term debt were used to repay the balance of the Company’s outstanding debt of $50 million in September 2002, pay outstanding balances in accounts payable related to the Company’s rig construction program, and for other general corporate purposes. At September 30, 2002, the Company had a committed unsecured line of credit totaling $125 million. Letters of credit totaling $10,587,260 were outstanding against the line, leaving $114,412,740 available to borrow. The line of credit matures in July 2003 and bears interest of LIBOR + .875 percent to 1.125 percent depending on certain financial ratios of the Company. The Company must maintain certain financial ratios as defined including debt to total capitalization and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of liquidity and tangible net worth. At September 30, 2002, the company held an unassociated interest rate swap tied to 30-day LIBOR in the amount of $50 million, which matures on October 27, 2003. The interest rate swap instrument originally was designed as a hedge of a $50 million loan that was paid off in September 2002. The interest rate swap was valued as a liability 34 35 of approximately $1.7 million on the date the $50 million debt was paid off. The $1.7 million will be amortized over the remaining life of the interest rate swap as interest expense. In 2002, $17,000 of this amortization was included in interest expense. Changes to the value of the interest rate swap subsequent to the date the $50 million debt was paid will be recorded to income. The strength of the Company’s balance sheet is substantial, with current ratios for September 30, 2002 and 2001 at 2.5 and 3.9, respectively, and with debt to total capitalization of 10 percent and 4.6 percent, respectively. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2002, had a market value of $175,668,000. The Company’s investments in Atwood Oceanics, Inc., Schlumberger, Ltd., Transocean, and ConocoPhillips make up over 90 percent of the portfolio’s market value. The portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding the Company’s equity-method investments, the portfolio is recorded at fair value on the Company’s balance sheet for each reporting period. During 2002, the Company paid a dividend of $0.305 per share, or a total of $15,221,084, representing the 31st consecutive year of dividend increases. S T O C K P O R T F O L I O H E L D B Y T H E C O M PA N Y September 30, 2002 Number of Shares Book Value Cost Market Value ( in thousands, except share amounts) Atwood Oceanics, Inc. Schlumberger, Ltd. Transocean Sedco Forex, Inc. ConocoPhillips Other Total 3,000,000 1,480,000 286,528 240,000 $ 58,937 23,511 9,509 5,976 8,849 $106,782 $ 87,750 56,921 5,960 11,098 13,939 $175,668 Q UA N T I TAT I V E A N D Q UA L I TAT I V E D I S C L O S U R E S A B O U T M A R K E T R I S K Foreign Currency Exchange Rate Risk The Company has international operations in several South American countries and a labor contract for work off the coast of Equatorial Guinea. With the exception of Venezuela, the Company’s exposure to currency valuation losses is usually minimal, due to the fact that virtually all billings and payments in other countries are in U.S. dollars. Even though the Company’s contract with its customers in Argentina were in U.S. dollars, Argentina experienced a dramatic economic collapse. As a result, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos, resulting in the Company recording a $1,200,000 loss for 2002. At the present time, the Company is not engaged in performing contract drilling services in Argentina, even though 2 rigs remain in that country. In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 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 2002, the Company experienced devaluation losses in Venezuela of $4,393,000, and losses of $796,000 in 2001, and $687,000 in 2000. The Company anticipates additional devaluation losses in Venezuela in 2003, but it is unable to predict the extent of the devaluation or its financial impact. Should Venezuela experience a 25 to 100 percent devaluation, Company losses could range from approximately $1,700,000 to $3,000,000. 36 37 Commodity Price Risk The demand for contract drilling services is a result of exploration and production companies spending money to explore and develop drilling prospects in search for crude oil and natural gas. Their appetite for such spending is driven by their cash flow and financial strength, which is very dependent, among other things, on crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile, and very difficult to predict. This difficulty has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services are not always purely a function of the movement of commodity prices. Interest Rate Risk As mentioned earlier, the Company has entered into a $200,000,000 intermediate term unsecured debt obligation with stage maturities from 5 to 12 years, with varying fixed interest rates for each maturity series. $100 million was outstanding at September 30, 2002, of which $12.5 million is due on August 15, 2007 and the remaining $87.5 million is due 2009 through 2014. The average interest rate during the next five years on this debt is 6.3 percent, after which it increases to 6.4 percent. The fair value of this debt at September 30, 2002 was approximately $109.7 million. At September 30, 2002, the Company held an interest rate swap on $50 million face value of debt to receive variable interest payments based on 30-day LIBOR rates and pay fixed interest payments of 5.4 percent through October 27, 2003. The swap instrument originally was designated as a hedge of a $50 million variable rate loan that was paid off in September 2002. The swap will result in monthly payments (receipts) to the extent 30-day LIBOR rates are less (greater) than 5.4 percent. At September 30, 2002, the fair value of the swap was a $1.7 million liability. At September 30, 2002, the Company had in place a committed unsecured line of credit totaling $125,000,000. Although there were letters of credit outstanding against the line, there had been no cash borrowings against the line of credit as of September 30, 2002. The Company’s line of credit interest rate is based on LIBOR plus .875 to 1.125 percent based on the Company’s EBITDA to net debt ratio. Should the Company need to draw on this line of credit, the Company would be subject to the interest rates prevailing during the term at which the Company had outstanding borrowings. Although market interest rates were at historical lows during fiscal year 2002, interest rates could rise for a number of various reasons in the future, and increase the Company’s total interest expense. Equity Price Risk At September 30, 2002, the Company owned stocks in other publicly held companies, with a total market value of $175,668,000. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the market value of the Company’s holdings. Except for the Company’s holdings in its equity affiliate, Atwood Oceanics, Inc., and its 50-50 joint venture investment with Atwood, the portfolio is recorded at fair value on its balance sheet, with changes in unrealized after-tax value reflected in the equity section of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial strength. 38 39 Report of Independent Auditors Consolidated Statements of Income 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, 2002 and 2001, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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, Years Ended September 30, 2002 2001 2000 REVENUES Operating revenues Income from investments COSTS AND EXPENSES Operating costs Depreciation General and administrative Interest (in thousands, except per share amounts) $482,484 $498,957 $360,632 28,444 10,317 31,510 510,928 509,274 392,142 336,890 308,437 234,132 61,447 20,391 ,980 49,532 16,627 1,701 77,317 13,612 2,730 419,708 376,297 327,791 on a test basis, evidence supporting the amounts and disclosures in the financial statements. An Income from continuing operations before income 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, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2002, in conformity with accounting principles generally accepted in the United States. E R N S T & Y O U N G L L P Tulsa, Oklahoma November 22, 2002 taxes and equity in income of affiliates 91,220 132,977 64,351 Provision for income taxes Equity in income of affiliates net of income taxes Income from continuing operations Income from discontinued operations 40,573 54,689 31,102 3,059 53,706 9,811 2,179 80,467 63,787 3,221 36,470 45,830 NET INCOME $ 63,517 $144,254 $ 82,300 Basic earnings per common share: Income from continuing operations Income from discontinued operations Net income Diluted earnings per common share: Income from continuing operations Income from discontinued operations Net income Average common shares outstanding Basic Diluted $ 1.08 $ 1.61 $ 0.74 0.19 1.27 0.92 $ 1.27 $ 2.88 $ 1.66 $ 1.07 $ 1.58 $ 0.73 0.19 1.26 0.91 $ 1.26 $ 2.84 $ 1.64 49,825 50,345 50,096 50,772 49,534 50,035 40 41 The accompanying notes are an integral part of these statements. Consolidated Balance Sheets ASSETS CURRENT ASSETS: September 30, 2002 2001 (in thousands) September 30, 2002 2001 (in thousands, except share data) LIABILITIES AND SHAREHOLDERS’ EQUITY Cash and cash equivalents $ 46,883 $ 128,826 Accounts receivable, less reserve of $1,337 in 2002 and $1,327 in 2001 Inventories Prepaid expenses and other Total current assets 92,604 22,511 16,753 178,751 116,752 23,553 31,269 300,400 Net assets of discontinued operations — 135,257 INVESTMENTS 146,855 200,286 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment Construction in progress Real estate properties Other Less-accumulated depreciation and amortization Net property, plant and equipment OTHER ASSETS TOTAL ASSETS The accompanying notes are an integral part of these statements. 1,235,784 997,177 72,303 48,925 82,310 30,838 50,579 78,420 1,439,322 1,157,014 541,877 897,445 506,963 650,051 4,262 14,127 $1,227,313 $1,300,121 CURRENT LIABILITIES: Accounts payable Accrued liabilities Total current liabilities NONCURRENT LIABILITIES: Long-term notes payable Deferred income taxes Other Total noncurrent liabilities SHAREHOLDERS’ EQUITY: Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Unearned compensation Accumulated other comprehensive income Less treasury stock, 3,518,282 shares in 2002 and 3,676,155 shares in 2001, at cost Total shareholders’ equity $ 41,045 $ 44,814 31,854 72,899 31,606 76,420 100,000 131,401 27,843 259,244 50,000 126,338 20,886 197,224 5,353 — 82,489 838,929 (190) 16,180 942,761 47,591 895,170 5,353 — 80,324 943,105 (1,812) 49,309 1,076,279 49,802 1,026,477 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $1,227,313 $1,300,121 The accompanying notes are an integral part of these statements. September 30, 2002 2001 2000 42 43 Consolidated Statements of Shareholders’ Equity Consolidated Statements of Cash Flows Balance, September 30, 1999 Comprehensive Income: Net Income Other comprehensive income: Unrealized gains on available- for sale securities, net Comprehensive income Cash dividends ($.285 per share) Exercise of Stock Options Purchase of stock for treasury Tax benefit of stock-based Awards Stock issued under Restricted Stock Award Plan Amortization of deferred Compensation Balance, September 30, 2000 Comprehensive Income: Net Income Other comprehensive income: Unrealized losses on available- for sale securities, net Derivatives instruments losses, net Total other comprehensive loss Comprehensive income Cash dividends ($.30 per share) Exercise of Stock Options Purchase of stock for treasury Tax benefit of stock-based Awards Amortization of deferred Compensation Balance, September 30, 2001 Comprehensive Income: Net Income Other comprehensive income: Unrealized losses on available- for sale securities, net Derivatives instruments losses, net Minimum pension liability adjustment, net Total other comprehensive loss Comprehensive income Distribution of Cimarex Energy Co. Stock Cash dividends ($.31 per share) Exercise of Stock Options Forfeiture of Restricted Stock Award Tax benefit of stock-based awards Amortization of deferred Compensation Common Stock Shares Amount Additional Paid-in Capital Unearned Compensation Retained Earnings Treasury Stock Shares Amount Accumulated Other Comprehensive Income (Loss) Total 53,529 $5,353 $61,411 4,491 31 157 53,529 5,353 66,090 (in thousands, except per share amounts) $ 745,956 $ (4,487) 3,903 $ (35,306) $ 75,182 82,300 (14,448) 30,882 (366) 21 3,253 (450) (248) (10) 91 1,458 (3,277) 77 813,885 144,254 3,548 (32,412) 106,064 (55,769) (986) 7,965 6,269 (15,047) (646) 774 5,808 (23,198) 53,529 5,353 80,324 1,465 (1,812) 13 943,105 63,517 3,676 (49,802) 49,309 (25,449) (68) (7,612) (152,201) (15,492) (181) 23 2,455 (244) $ 838,929 3,518 $ (47,591) $16,180 156 1,466 $ (190) 44 1,099 88 978 $ 848,109 82,300 30,882 113,182 (14,448) 7,744 (450) 31 — 1,535 955,703 144,254 (55,769) (986) (56,755) 87,499 (15,047) 13,773 (23,198) 6,269 1,478 1,026,477 63,517 (25,449) (68) (7,612) (33,129) 30,388 (152,201) (15,492) 3,554 — 978 1,466 $ 895,170 Balance, September 30, 2002 53,529 $5,353 $82,489 The accompanying notes are an integral part of these statements. Years Ended September 30, 2002 2001 2000 (in thousands) $ 53,706 $ 80,467 $ 36,470 61,447 (5,014) 1,122 (24,347) (1,392) 791 24,148 1,042 24,381 (3,769) 955 24,133 (5,429) 98,068 151,774 49,532 (3,593) 1,135 (1,189) (4,201) 876 77,317 (5,196) 1,200 (24,000) (959) 629 (49,405) (68) (11,411) 29,290 18,435 15,291 2,276 46,968 127,435 11,932 (40) (7,466) (2,301) (2,533) 17,623 (4,782) 61,424 97,894 (312,064) — 4,135 (5,656) 47,146 (266,439) (184,668) (2,279) 11,984 — 24,438 (150,525) (65,820) — 16,013 — 12,569 (37,238) 100,000 (50,000) (15,221) — 3,554 38,333 — — (15,047) (23,198) 13,601 (24,644) — (5,000) (14,175) (450) 5,437 (14,188) 62,792 (55,232) (13,171) (5,611) 157,286 (88,813) — 68,473 103,942 (64,081) — 39,861 (81,943) 128,826 $ 46,883 20,739 108,087 86,329 21,758 $128,826 $108,087 OPERATING ACTIVITIES: Income from continuing operations Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation Equity in income of affiliates before income taxes Amortization of deferred compensation Gain on sales of securities and non-monetary investment loss Gain on sale of property, plant and equipment Other – net Change in assets and liabilities: Accounts receivable Inventories Prepaid expenses and other Accounts payable Accrued liabilities Deferred income taxes Other noncurrent liabilities Net cash provided by operating activities INVESTING ACTIVITIES: Capital expenditures Acquisition of business, net of cash acquired Proceeds from sale of property, plant and equipment Purchase of investments Proceeds from sale of securities Net cash used in investing activities FINANCING ACTIVITIES: Proceeds from notes payable Payments on notes payable Dividends paid Purchases of stock for treasury Proceeds from exercise of stock options Net cash provided by (used in) financing activities DISCONTINUED OPERATIONS: Net cash provided by operating activities Net cash (used in) investing activities Cash of discontinued operations at spinoff Net cash provided by (used in) discontinued operations Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period The accompanying notes are an integral part of these statements. 45 Notes to Consoldiated Financial Statements September 30, 2002, 2001 and 2000 NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF 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. BASIS OF PRESENTATION On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders. Cimarex Energy Co. held the Company’s exploration and production business and has been accounted for as discontinued operations in the accompanying consolidated financial statements. Unless indicated otherwise, the information in the notes to consolidated financial statements relates to the continuing operations of the Company (see Note 2). 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 2002, 2001 and 2000 was $5,473,000, $494,000, and $664,000, respectively. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires man- agement to make estimates and assumptions that affect the amounts reported in the consolidated financial state- ments and accompanying notes. Actual results could differ from those estimates. PROPERTY, PLANT AND EQUIPMENT 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 expected to be generated by the asset are not sufficient to recover the carrying amount of the asset. The impairment loss is calculated as the difference between fair value and carrying amount of the long-lived asset. Fair value on all long-lived assets are based on discounted future cash flows or information provided by sales and pur- chases of similar assets. Substantially all property, plant and equipment is depreciated using the straight-line method based on the following estimated useful lives: Contract drilling equipment Real estate buildings and equipment Other Years 4-15 10-50 3-33 As the result of an economic evaluation of useful lives of its drilling equipment, the Company extended the depre- ciable life of its rig equipment from 10 to 15 years. This change provides 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 2002 and 2001 by approximately $30.0 million each year. 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 AND SUPPLIES Inventory and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventory and supplies are valued at the lower of cost (moving average or actual) or market value. 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 contract drilling revenues also include revenues of $4,109,000 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. For certain contracts, the Company receives lump-sum payments for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. 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 2002 and 2001 includes a loss of approximately $0.5 million, $0.01 per share on a diluted basis, and $1.4 million, $0.03 per share on a diluted basis, respectively, 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. There were no similar losses incurred in 2000. 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, 2002 and 2001. The quoted market value of the Company’s investment was $87,750,000 and $78,000,000 at September 30, 2002 and 2001, respectively. Retained earnings at September 30, 2002 includes approximately $29,720,000 of undistributed earnings of Atwood. 46 47 Summarized financial information of Atwood is as follows: TREASURY STOCK Gross revenues Costs and expenses Net income September 30, 2002 $149,157 120,872 $ 28,285 2001 (in thousands) $147,541 120,195 $ 27,346 2000 $134,514 111,366 $ 23,148 Helmerich & Payne, Inc.’s equity in net income, net of income taxes $ 4,206 $ 3,596 $ 3,221 Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity $ 71,771 372,715 24,417 143,967 276,102 $ 45,891 304,857 19,144 85,948 245,656 $ 64,917 248,334 17,484 77,562 218,205 Helmerich & Payne, Inc.’s investment $ 58,937 $ 52,153 $ 46,353 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 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 2002, 2001 and 2000 was $2.5 million, $1.3 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, 2002, 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. 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. The company has one derivative, an interest rate swap, that is discussed further in Note 3. 48 49 NOTE 2 DISCONTINUED OPERATIONS On February 22, 2002, the Company’s board of directors approved and on February 23, 2002, the Company entered into an Agreement and Plan of Merger and related agreements with Key Production Company, Inc., including a Distribution Agreement between the Company and Cimarex Energy Co. The agreements provided for the consolidation of the Company’s exploration and production business under Cimarex Energy Co.; the distribution of 100 percent of the Cimarex Energy Co. common stock to the Company’s shareholders; and the merger of Key Production Company, Inc. with a subsidiary of Cimarex Energy Co. In July of 2002, the Company obtained a Private Letter Ruling from the Internal Revenue Service to the effect that the contribution and transfer of the assets and liabilities of the Company’s exploration and production business to Cimarex Energy Co. and the distribution by the Company of all shares of Cimarex Energy Co. common stock to the holders of the Company’s common stock would generally be treated as a tax-free transaction for U.S. federal income tax purposes. Although private letter rulings are generally binding on the IRS, the Company will not be able to rely on this ruling if any of the factual representations or assumptions that were made to obtain the ruling are, or become, incorrect or untrue in any material respect. However, the Company is not aware of any facts or circumstances that would cause any of the representations or assumptions to be incorrect or untrue in any material respect. The distribution could also become taxable to the Company, but not the Company’s shareholders, under the Internal Revenue Code (IRC) in the event the Company’s subsequent business combinations were deemed to be part of a plan contemplated at the time of distribution and would constitute a total cumulative change of more than 50 percent of the equity interest in either company. On September 30, 2002, the Company’s distribution of 100 percent of the common stock of Cimarex Energy Co. and the subsequent merger of Key Production Company, Inc. was completed. Upon completion of the merger, approximately 26.6 million shares of the Cimarex Energy Co. common stock on a diluted basis was distributed to shareholders of the Company of record on September 27, 2002. The Cimarex Energy Co. stock distribution was recorded as a dividend and resulted in a decrease to consolidated shareholders’ equity of approximately $152.2 million. Following this transaction, the Company and its subsidiaries will continue to own and operate the contract drilling and real estate businesses, and Cimarex Energy Co. will be a separate, publicly-traded company that will own and operate the exploration and production business. The company does not own any common stock of Cimarex Energy Co. Under terms of a tax sharing agreement, each party has agreed to indemnify the other in respect of all taxes for which it is responsible under the tax sharing agreement. Cimarex is responsible for all taxes related to the exploration and production business for all of past and future periods, including all taxes arising from the Cimarex business prior to the time that Cimarex was formed, and agrees to hold the Company harmless in respect of those taxes. Cimarex is entitled to receive all refunds and credits of taxes previously paid with respect to the exploration and production business. Cimarex will not receive the benefit of any loss or similar tax attribute arising during the time that losses from the Cimarex business are included in the Company’s consolidated federal income tax return. The Company remains responsible for all taxes related to the business of the Company other than the exploration and production business and has agreed to indemnify Cimarex in respect of any liability for any such taxes. Summarized results of discontinued operations for the years ended September 30, 2002, 2001 and 2000, are as follows: Revenues Income from operations: Income before income taxes Tax provision 2002 2001 2000 $172,827 (in thousands) $317,580 $238,953 15,138 5,327 102,125 38,338 72,412 26,582 Income from discontinued operations $ 9,811 $ 63,787 $ 45,830 Net assets of discontinued operations as of September 30, 2001 are as follows: Current assets Property, plant and equipment – net Other assets Total assets Current liabilities Deferred income taxes Other liabilities and deferred income Total liabilities Net assets of discontinued operations 2001 (in thousands) $ 31,012 168,353 278 199,643 44,801 18,101 1,484 64,386 $135,257 50 51 NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT NOTE 4 INCOME TAXES On October 15, 2002, the Company received an additional $100 million in long-term debt proceeds under the TOTAL PROVISION: In August 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities from 5 to 12 years. At September 30, 2002, the Company had $100 million in debt out- standing at fixed rates and maturities as summarized in the following table. Issue Amount $12,500,000 $12,500,000 $37,500,000 $37,500,000 Maturity Date August 15, 2007 August 15, 2009 August 15, 2012 August 15, 2014 Interest Rate 5.51% 5.91% 6.46% 6.56% same debt agreements and with identical issue amounts, maturity dates, and interest rates as listed above. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. Proceeds from the intermediate-term debt was used to repay the balance of the Company’s outstanding debt of $50 million in September 2002, pay outstanding balances in accounts payable related to the Company’s rig construction program and for other general corporate purposes. At September 30, 2002, the Company had a committed unsecured line of credit totaling $125 million. Letters of credit totaling $10.6 million were outstanding against the line, leaving $114.4 million available to borrow. Under terms of the line of credit, the Company must maintain certain financial ratios as defined including debt to total capitalization and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of liquidity and tangible net worth. Commitment fees of $175,000 were paid on the facility in July 2002. A non-use fee of 0.15 percent per annum is calculated on the average daily unused amount, payable quarterly. The interest rate varies based on LIBOR plus .875 to 1.125 depending on ratios described above. The line of credit matures in July, 2003. At September 30, 2002, the Company held an unassociated interest rate swap tied to 30-day LIBOR in the amount of $50 million which matures on October 27, 2003. The swap instrument was originally designated as a hedge of a $50 million loan that was paid-off in September 2002. The swap liability was valued at $1.7 million on September 30, 2002. The interest rate swap liability was valued at approximately $1.7 million on the date the $50 million debt was paid-off. The $1.7 million will be amortized over the remaining life of the swap as interest expense. In 2002, $17,000 of this amortization was included in interest expense. Changes to the value of the interest rate swap subsequent to the date the $50 million debt was paid will be recorded to income. CURRENT: Federal Foreign State DEFERRED: Federal Foreign State The components of the provision for income taxes from continuing operations are as follows: Years Ended September 30, 2002 2001 (In thousands) $ 13,324 $ 28,911 5,080 1,022 19,426 16,019 3,732 1,396 21,147 $ 40,573 8,870 2,651 40,432 8,850 4,701 706 14,257 $ 54,689 2001 (In thousands) $106,163 26,814 $132,977 2000 $ 5,316 8,766 714 14,796 9,085 6,146 1,075 16,306 $31,102 2000 $ 56,961 7,390 $ 64,351 The amounts of domestic and foreign income from continuing operations are as follows: 2002 Years Ended September 30, INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES: Domestic Foreign $ 82,012 9,208 $ 91,220 Effective income tax rates on income from continuing operations as compared to the U.S. Federal income tax rate are as follows: Years Ended September 30, 2002 2001 U.S. Federal income tax rate Effect of foreign taxes Other, net Effective income tax rate 35% 7 2 44% 35% 4 2 41% 2000 35% 12 1 48% The components of the Company’s net deferred tax liabilities are as follows: September 30, 2002 2001 2000 DEFERRED TAX LIABILITIES: Property, plant and equipment Available-for-sale securities Equity investments Other Total deferred tax liabilities DEFERRED TAX ASSETS: Financial accruals Other Total deferred tax assets NET DEFERRED TAX LIABILITIES (In thousands) $ 111,822 $ 81,677 25,221 11,165 — 148,208 9,998 6,809 16,807 33,937 15,637 505 131,756 3,031 2,387 5,418 $ 131,401 $126,338 52 53 NOTE 5 SHAREHOLDERS’ EQUITY In December 2001, the board of directors authorized the repurchase of up to 2,000,000 shares per calendar year 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. The following summary reflects the stock option activity for the Company’s common stock and related information for 2002, 2001, and 2000. (shares in thousands): 2002 2001 2000 Options Weighted-Average Exercise Price Options Weighted-Average Exercise Price Options Weighted-Average Exercise Price During fiscal 2001 the Company purchased 773,800 shares at a cost of approximately $23,198,000, and in Outstanding at October 1, 3,136 $25.78 2,955 $22.94 2,574 $21.34 fiscal 2000 the Company purchased 20,600 shares at a cost of approximately $450,000. The Company did not purchase any shares in fiscal 2002. 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. 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. In fiscal 2002, 819,800 options were granted under the 2000 plan. There were no restricted stock grants in fiscal 2002. On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. Granted Exercised Adjustment for Cimarex spinoff Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 820 (181) 926 (826) 3,875 1,935 2,195 29.89 19.61 — 28.15 $20.28 $19.07 844 (644) — (19) 3,136 1,078 3,000 32.36 21.34 — 25.57 $25.78 $23.82 767 (364) — (22) 2,955 1,046 1,077 24.75 15.44 — 23.00 $22.94 $22.40 The following table summarizes information about stock options at September 30, 2002 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $10.22 to $12.78 $12.79 to $19.84 $19.85 to $28.04 $10.22 to $28.04 Options 397 1,460 2,018 3,875 Weighted-Average Remaining Life Weighted-Average Exercise Price 2.9 6.2 7.9 6.8 $10.58 $16.94 $24.60 $20.28 Options 363 927 645 1,935 Weighted-Average Exercise Price $10.58 $16.91 $26.96 $19.07 to the Company's shareholders. The distribution was recorded as a dividend and resulted in a decrease to The following table reflects pro forma net income and earnings per share had the Company elected to adopt the fair consolidated shareholders’ equity of approximately $152.2 million. Any options held by Cimarex employees at value method of SFAS No. 123, “Accounting for Stock-Based Compensation”, in measuring compensation cost begin- the distribution date were automatically forfeited per the terms of the Company's stock incentive plans. Both vested and unvested options held by remaining participants at September 30, 2002 were adjusted (the number of options and exercise price) to reflect the change in the value of Company stock as the result of the spin-off of Cimarex. The adjustment was made in such a way that aggregate intrinsic value of the options and the ratio of the exercise price per share to the market value per share remained the same. ning with 1997 employee stock-based awards. Years Ended September 30, 2002 2001 2000 (in thousands, except per share data) Net income: As reported Pro forma Basic earnings per share: As reported Pro forma Diluted earnings per share: As reported Pro forma $63,517 $61,072 $ $ $ $ 1.27 1.23 1.26 1.21 $144,254 $139,211 $ 2.88 $ 2.78 $ 2.84 $ 2.74 $82,300 $78,788 $ 1.66 $ 1.59 $ 1.64 $ 1.57 54 55 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 2002, 2001 and 2000 were $12.47, $13.01, and $10.80, 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: Expected years until exercise Expected stock volatility Dividend yield Risk-free interest rate 2002 4.5 48% .8% 4.0% 2001 4.5 43% .8% 5.2% 2000 5.5 41% .8% 6.0% On September 30, 2002, the Company had 50,010,670 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 6 EARNINGS PER SHARE A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: Basic weighted-average shares Effect of dilutive shares: Stock options Restricted stock 2002 49,825 508 12 520 2001 (in thousands) 50,096 644 32 676 2000 49,534 492 9 501 Diluted weighted-average shares 50,345 50,772 50,035 Restricted stock of 44,675 shares at a weighted-average price of $30.38 and options to purchase 451,421 shares of common stock at a weighted-average price of $27.98 were outstanding at September 30, 2002 but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 2001, restricted stock of 120,018 shares at a weighted-average price of $37.73 and options to purchase 1,250,750 shares of common stock at a price of $33.84 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, 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. 56 57 NOTE 7 FINANCIAL INSTRUMENTS NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The Company had $100 million of intermediate-term debt outstanding at September 30, 2002, which had an estimated fair value of $109.7 million. The debt was valued based on the prices of similar securities with similar terms and credit ratings. The Company used the expertise of an outside investment banking firm to assist with the estimate of the fair value of the intermediate-term debt. The Company’s line of credit and 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 a liability of $1.7 million at September 30, 2002, 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): Equity Securities: September 30, 2002 September 30, 2001 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $ 46,325 $ 63,778 $ 43,846 $ 84,257 $ 3,772 $ 3,136 $ 86,399 $ 144,899 During the years ended September 30, 2002, 2001, and 2000, marketable equity available-for-sale securities with a fair value at the date of sale of $46,692,000, $24,439,000, and $12,640,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $25,661,000, $3,314,000, and $12,576,000, respectively. The table below presents changes in the components of accumulated other comprehensive income (loss). Unrealized Appreciation (Depreciation) on Securities Interest Rate Swap Minimum Pension Liability Total (in thousands) Balance at September 30, 1999 $75,182 $ — $ — $75,182 2000 Change: Pre-income tax amount Income tax provision Realized gains in net income (net of $9,120 income tax) Balance at September 30, 2000 2001 Change: Pre-income tax amount Income tax provision Realized gains in net income (net of $452 income tax) Balance at September 30, 2001 2002 Change: Pre-income tax amount Income tax provision Amortization of swap 73,810 (28,048) (14,880) 30,882 106,064 (88,762) 33,730 (737) (55,769) 50,295 (16,228) 6,167 (net of $7 income tax benefit) — Realized gains in net income (net of $9,431 income tax) Balance at September 30, 2002 (15,388) (25,449) $24,846 — — — — — (1,590) 604 — (986) (986) (127) 48 11 — (68) — — — — — — — — — — (12,277) 4,665 — — (7,612) $(1,054) $ (7,612) 73,810 (28,048) (14,880) 30,882 106,064 (90,352) 34,334 (737) (56,755) 49,309 (28,632) 10,880 11 (15,388) (33,129) $16,180 58 59 COMPONENTS OF NET PERIODIC PENSION EXPENSE: Years Ended September 30, 2002 Service cost Interest cost Expected return on plan assets Amortization of prior service cost Amortization of transition asset Recognized net actuarial (gain) loss Net pension expense Defined Contribution Plan: 2001 (in thousands) $3,851 3,330 (5,415) 238 (540) 17 2000 $ 3,427 2,741 (5,226) 238 (540) (303) $4,769 3,835 (4,804) 238 (540) 120 $3,618 $1,481 $ 337 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 $5,226,000, $4,499,000, and $3,188,000 in 2002, 2001, and 2000, respectively. NOTE 9 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 September30, 2002 2001 (in thousands) Benefit obligation at beginning of year $ 51,733 $44,838 Service cost Interest cost Curtailment Actuarial loss Benefits paid Benefit obligation at end of year 4,769 3,835 (1,232) 11,036 (2,007) $ 68,134 3,851 3,330 — 903 (1,189) $51,733 CHANGE IN PLAN ASSETS: Years Ended September 30, 2002 2001 (in thousands) Fair value of plan assets at beginning of year $ 53,987 $60,611 Actual loss on plan assets (3,694) Benefits paid (2,007) (5,435) (1,189) Fair value of plan assets at end of year $ 48,286 $53,987 Funded status of the plan $ (19,848) Unrecognized net actuarial (gain) loss Unrecognized prior service cost Unrecognized net transition asset Accumulated other comprehensive income (before tax) Prepaid (accrued) benefit cost WEIGHTED-AVERAGE ASSUMPTIONS: 24,929 284 — $ 2,254 6,720 548 (540) (12,277) — $ (6,912) $ 8,982 Discount rate Expected return on plan Rate of compensation increase Years Ended September 30, 2002 6.75% 2001 7.50% 9.00% 5.00% 2000 7.50% 9.00% 5.00% 8.00% 5.00% 60 61 NOTE 10 OTHER CURRENT ASSETS AND ACCRUED LIABILITIES Prepaid expenses and other consist of the following: Time deposits Prepaid income tax Prepaid - other Accrued liabilities consist of the following: Taxes payable – operations Income taxes payable Workers compensation claims Payroll and employee benefits Loss contingency (see note 14) Deferred income Other September 30, 2002 2001 2000 (in thousands) $ 337 9,304 7,112 $16,753 $ 5,253 11,218 14,798 $31,269 September 30, 2002 2001 2000 (in thousands) $ 7,660 $ 5,123 — 2,506 7,032 — 6,016 8,640 739 2,585 5,676 10,000 — 7,483 $31,854 $31,606 NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2002 Interest paid Income taxes paid $ 2,929 $ 9,779 2001 (in thousands) $ 2,668 $42,523 2000 $ 2,851 $34,295 NOTE 12 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. 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. NOTE 13 NEW ACCOUNTING STANDARDS 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 Company anticipates no impact on the Company’s results of operations and financial position upon adopting SFAS No. 143. 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. 62 63 The Statement will be applied prospectively and is effective for financial statements issued for fiscal years beginning after December 15, 2001. The Company’s approach for impairment under SFAS No. 121 is consistent with the provisions under SFAS No. 144. Accordingly, adopting this statement on the Company’s results of operations and financial position will not be different than if the Company continued to use SFAS No. 121. NOTE 14 CONTINGENT LIABILITIES AND COMMITMENTS LITIGATION SETTLEMENT The Company was a defendant in Verdin v. R&B Falcon Drilling USA, Inc., et al., a civil action in the United States District Court, Galveston, Texas. 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 incurred a net charge of $3.25 million to contract drilling expense based on the pending settlement. The Court approved the settlement on April 25, 2002. In June, 2002, the Company paid $10 million to settle all claims in this litigation. The Company was reimbursed $6.75 million in June, 2002 by the Company’s insurer. COMMITMENTS The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2002, the Company has commitments of approximately $150 million for the purchase of drilling equipment. NOTE 15 SEGMENT INFORMATION The Company operates principally in the contract drilling industry, which includes a Domestic segment and an International segment. The contract drilling operations consist of contracting Company-owned drilling equip- ment primarily to major oil and gas exploration companies. The Company’s primary international areas of operation include Venezuela, Colombia, Ecuador, Argentina and Bolivia. 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. As described in Note 2 the Company’s oil and gas operations were distributed to Company shareholders on September 20, 2002. Such operations have been treated as discontinued operations and have been excluded from these segment disclosures. 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, and depreciation but excludes general and administrative expense, interest expense and corporate depreciation and other income (expense). 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. Summarized financial information of the Company’s reportable segments for continuing operations for each of the years ended September 30, 2002, 2001, and 2000 is shown in the following table: (in thousands) 2002: Contract Drilling Domestic International Services Real Estate Other Eliminations Total 2001: Contract Drilling Domestic International Services Real Estate Other Eliminations Total 2000: Contract Drilling Domestic International Services Real Estate Other Eliminations Total External Sales Inter- Segment Total Sales Operating Profit Depreciation Total Assets Additions to Long-Lived Assets $335,704 138,623 474,327 8,525 28,076 — $510,928 $332,399 154,890 487,289 11,018 10,967 — $509,274 $214,531 136,549 351,080 8,999 32,063 — $392,142 $ 809 — 809 1,491 — (2,300) $ — $4,487 — 4,487 1,545 — (6,032) $ — $ 3,048 — 3,048 1,545 — (4,593) $ — $336,513 138,623 475,136 10,016 28,076 (2,300) $510,928 $ 69,181 13,128 82,309 5,064 — — $ 87,373 $37,120 20,336 57,456 1,844 2,147 — $61,447 $ 728,611 254,940 983,551 26,562 217,200 — $1,227,313 $284,527 23,157 307,684 3,181 1,199 — $312,064 $336,886 154,890 491,776 12,563 10,967 (6,032) $509,274 $107,691 28,475 136,166 6,315 — — $142,481 $26,277 18,838 45,115 2,284 2,133 — $49,532 $ 506,173 268,947 775,120 22,621 367,123 — $1,164,864 $144,063 38,022 182,085 1,190 1,393 — $184,668 $217,579 136,549 354,128 10,544 32,063 (4,593) $392,142 $ 35,808 9,753 45,561 5,346 — — $ 50,907 $35,355 38,101 73,456 1,611 2,250 — $ 342,278 259,892 602,170 24,235 436,269 — $77,317 $1,062,674 $ 40,722 13,825 54,547 2,909 8,364 — $ 65,820 64 65 The following table reconciles segment operating profit per the table on page 65 to income before taxes and equity in income of affiliates as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, 2002 2001 2000 Segment operating profit Unallocated amounts: Income from investments General and administrative expense Interest expense Corporate depreciation Other corporate income (expense) Total unallocated amounts Income before income taxes and equity in income of affiliates $87,373 $142,481 $50,907 28,444 (20,391) (980) (2,147) (1,079) 3,847 10,317 (16,627) (1,701) (2,133) 640 (9,504) 31,510 (13,612) (2,730) (2,250) 526 13,444 $91,220 $132,977 $64,351 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, 2002 2001 2000 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $372,305 47,118 45,433 9,559 36,513 $510,928 $698,316 72,630 49,353 14,339 62,807 $897,445 $354,384 43,409 35,793 27,045 48,643 $509,274 $448,119 84,856 33,520 16,195 67,361 $650,051 $255,593 34,922 20,422 42,509 38,696 $392,142 $330,711 37,001 30,636 26,361 102,014 $526,723 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 15.7 percent, 24.2 percent, and 24.4 percent of the total consolidated revenues during the years ended September 30, 2002, 2001 and 2000, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 14.6 percent, 12.9 percent, and 11.9 percent of total consolidated revenues in the years ended September 30, 2002, 2001 and 2000, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 12.0 percent, 8.3 percent, and 7.3 percent of total consolidated revenues in the years ended September 30, 2002, 2001 and 2000, respectively. Collectively, the receivables from these customers were approximately $35.0 million and $40.5 million at September 30, 2002 and 2001, respectively. NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2002 Revenues Gross profit Income from continuing operations Net income Basic earnings per common share: Income from continuing operations Net income Diluted earnings per common share: Income from continuing operations Net income 2001 Revenues Gross profit Income from continuing operations Net income Basic earnings per common share: Income from continuing operations Net income Diluted earnings per common share: Income from continuing operations Net income (in thousands, except per share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $134,992 $120,950 $139,709 $115,277 33,878 18,127 15,604 19,821 8,129 10,872 44,200 22,551 28,218 14,692 4,899 8,823 .36 .31 .36 .31 .16 .22 .16 .22 .46 .57 .45 .56 .10 .18 .10 .17 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $106,009 $115,186 $141,336 $146,743 28,086 13,956 33,840 29,520 14,105 41,749 44,011 24,154 40,437 49,688 28,252 28,228 .28 .68 .27 .67 .28 .83 .28 .82 .48 .80 .47 .79 .57 .57 .56 .56 Gross profit represents total revenues less operating costs and depreciation. 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 third quarter of 2002 includes after-tax gains on sale of available-for-sale securities of $15.2 million, $0.30 per share, on a diluted basis. 66 67 Directors Officers W. H. Helmerich, III Chairman of the Board Tulsa, Oklahoma Hans Helmerich President and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong** Chairman Transland Financial Services, Inc. Denver, Colorado Glenn A. Cox* President and Chief Operating Officer, Retired Phillips Petroleum Company Bartlesville, Oklahoma George S. Dotson Vice President, President of Helmerich & Payne International Drilling Co. Tulsa, Oklahoma Paula Marshall-Chapman President and Chief Executive Officer The Bama Companies, Inc. 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 W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer George S. Dotson Vice President, President of Helmerich & Payne International Drilling Co. Douglas E. Fears Vice President and Chief Financial Officer Steven R. Mackey Vice President, Secretary, and General Counsel Stockholders’ Meeting The annual meeting of stockholders will be held on March 5, 2003. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to share- holders on or about January 24, 2003. 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 finan- cial 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 13, 2002, there were 1,001 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 Additional Information Quarterly reports on Form 10-Q, earnings releases, and financial statements are made available on the investor relations section of the Company’s Web site. Quarterly reports on Form 10-Q, earnings releases, and financial statements are also 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 68 

Continue reading text version or see original annual report in PDF format above