Helmerich & Payne, Inc. Helmerich & Payne, Inc. is the holding Company for Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore platform operations in the United States, South America, Africa, and Europe. Holdings also include commercial real estate properties in the Tulsa, Oklahoma, area and an energy-weighted portfolio of publicly-traded securities valued at approximately $170 million as of September 30, 2003. At the end of 2002, the Company completed the spin-off of Cimarex Energy Co. to shareholders. Cimarex, the Company’s former exploration and production division, was merged with Key Production Company, Inc. and currently trades on the New York Stock Exchange under the symbol XEC. F I N A N C I A L H I G H L I G H T S Years Ended September 30, 2003 2002 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) $ 515,284 $ 551,879 17,873 17,873 0.35 0.35 0.32 246,301 1,415,835 53,706 63,517 1.07 1.26 0.305 312,064 1,227,313 President’s Letter To the Co-owners of Helmerich & Payne, Inc. It seems every year the oil and gas business plays an important role on the stage of political and economic events. Few years can match 2003 for the sheer number of headline stories. In the heart of the Middle East, Operation Iraqi Freedom brought the quick overthrow of Saddam Hussein. During the time leading up to the war, Venezuela sustained a crippling two-month nationwide strike, threatening an important source of U.S. crude oil. In the spring, record low natural gas inventories and declining production rates prompted Federal Reserve Chairman Alan Greenspan to warn of a potential natural gas shortage and the serious consequences it posed to economic recovery. Later in the summer, the Northeast sustained a sweeping electrical blackout that stranded 50 million customers. With this backdrop, the President hoped to sign legislation representing the first serious effort in decades at shaping a national energy policy. Before failing by two votes to another Democratic filibuster, the energy bill had mushroomed to over a thousand pages and an estimated cost of some $100 billion, bearing only a weak resemblance to the President’s original request. The energy bill represented an unworkable combination: too much pork and too little beef. Pork barrel spending included increased subsidies for ethanol and soybean based fuel mandates, add-ons like aid for an energy efficient shopping mall in Syracuse, and even money for a pet rainforest project in Iowa. While spending ballooned to more than three times the Administration’s stated limit, one of the President’s priorities, the approval for exploration in Alaska’s Arctic National Wildlife Refuge, was thrown overboard early in the Congressional negotiations. In the end, too little was done to streamline and open access to high potential natural gas exploratory plays on Federal lands, and to promote nuclear power, and to develop clean burning coal technology. All three are important components to a balanced U.S. energy supply. What are the prospects for the passage of an energy bill during the upcoming election year? Any attempt should speak clearly to the practical challenges of fueling the world’s largest economy. Lewis Lehrman finds that voice in his piece, “Energetic America,” where he argues for an energy policy that promotes a diverse supply base that is both affordable and dependable. He points out that we are in a time when effective economic and energy policies are indispensable to national security issues, and states, “Combined with President Bush’s supply-side tax policy, an unselfconscious supply-side energy and regulatory policy will lead to abundant and cheaper energy, growth of economic opportunity, and full employment.” However future politics get sorted out, oil and gas will remain at the center of the energy picture for years to come. Your Company plays an important role in providing new supplies to help meet this growing demand. As we go forward, we look to the opportunities ahead. Sincerely, Hans Helmerich President December 15, 2003 Contract Drilling Operations The Company’s first full year as a stand-alone drilling contractor was accompanied by a number of unusual factors: high oil and natural gas prices, a second war in the Persian Gulf, and a major strike in Venezuela, which resulted in turmoil within PDVSA, the Company’s largest customer in South America. The Baker Hughes U.S. Land Rig Count increased by over 30 percent in fiscal 2003, but the journey was bumpy and cautious. The Company delivered 19 third generation FlexRigs* to the U.S. market in 2003, expanding its capacity in this segment by nearly one-third. One of the uncertainties ahead is the U.S. offshore platform market, which softened considerably in 2003. The Company’s South American markets also remain weak due in large part to socio-economic and political factors. During 2003, the Company introduced its first generation FlexRig into two new international markets. U.S. Land Operations On average, the Company worked 14 more rigs during the year than in 2002, but lower dayrates, combined with higher training and depreciation expenses associated with the FlexRig3 project, muted financial results for 2003 compared to 2002. At the close of the year, 68 out of 83 available rigs were working. The Company’s fleet of 43 FlexRigs and 11 highly mobile rigs maintained an average utilization of 95 percent during the year, while the remaining 29 conventional rigs had an average utilization rate of 58 percent. Demand continues to be weakest in the deep-drilling end of the business where soft rates are under increasing price competition. Out of the Company’s 16 deep-rated conventional rigs, 11 were idle at the close of the fiscal year. By contrast, the Company had only one idle * The term “FlexRig” used throughout this Annual Report is a Company trademark Registered in the U.S. Patent and Trademark Office. rig out of the remaining 13 conventional rigs rated at 20,000 feet or less. The FlexRig, with its flexible depth capacity range of 8,000 to 18,000 feet, has shifted the Company’s fleet capability toward the larger medium- depth segment of the drilling market, and this is having a positive impact on the Company’s activity rate. At the close of 2003, the Company had 27 FlexRig3s operating, and the results in the field continue to prove their value. Of the 173 wells completed by FlexRig3s this past year, better than two out of three have come in ahead of customer-estimated drilling times. The Company’s investment in employee screening, training, and team building for the FlexRig3 is also paying dividends. Eighteen months into the FlexRig3 project, the Company has achieved a retention rate of 78 percent on the initial training effort. Well-trained and stable crews have enabled the project to achieve outstanding field results, and more customers and their non-operating partners are seeing how FlexRigs can lower well costs, reduce well cycle times, and increase productivity. Throughout 2003, FlexRig3s were nearly 100 percent utilized and working at premium dayrates. Overall, the U.S. land market appears to be in the early stages of a cyclical transition. Drilling services, as well as other oilfield services and supplies, typically gain more pricing power as supply and demand tighten because of reduced industry capacity. It is in this market phase that the distinct advantages of the FlexRig technology will be most apparent to customers as they begin to refocus on total project costs. U.S. Offshore Operations Activity in the offshore platform segment declined by almost one-third during 2003, with five of the Company’s 12 offshore platform rigs under contract in the Gulf of Mexico at year-end. The Company also operated one rig in the Gulf of Mexico and two rigs offshore California under management contracts during 2003. The overall profit margin in the offshore segment is likely to come under increasing pressure during the coming year as some of the working rigs are on long-term projects that have reached the full development stage and will likely alternate between operating rates and the lower standby rates. Out of the seven rigs that are idle in the Company’s fleet, six are capable of returning to work on short notice and the seventh will require shipyard maintenance. The Company retains a large share of the offshore platform market and has considerable design and construction experience in conventional, spar, and deep-water tension-leg platform rigs. The Company is well positioned to compete for any opportunities that emerge in the coming year; however, we expect that any recovery in the platform market will be slow due to long project lead times. International Operations An average of 12 rigs were fully employed in 2003, compared to 16 rigs in 2002. Ecuador remained the most active country with an average of seven rigs working, followed by Venezuela with an average of four rigs, and Colombia and Bolivia each with less than a full rig year of activity. Operations in Venezuela are improving as seven rigs were working shortly after the close of the fiscal year, and an eighth rig is expected to start work in the second quarter. Despite numerous challenges presented in Venezuela, we are encouraged by the recent increase in activity. Venezuela still has promising growth potential, and the Company has the best-equipped and maintained rig fleet in the country. Two first generation FlexRigs were committed to short-term international contracts in 2003. The first is working for a U.S. based independent in Hungary where, at year-end, it was drilling its third well after a smooth, incident-free start-up. Having previously used a FlexRig in U.S. operations, the customer desired to see the technology, versatility, and mobility of these rigs employed in an important international project. The second FlexRig was deployed for a major international operator under a multi- well contract in the central African nation of Chad. This project is scheduled to begin drilling in December 2003. Outlook Looking to 2004 and beyond, we see significant opportunities for a growing international business and believe the Company brings a distinctive combination of experience and innovation to this market. The FlexRig will play an important role in capturing this potential, as we endeavor to introduce this unique technology to international markets. While this transition year was not what we had hoped for financially, the Company improved operating performance, expanded its capacity, and is well positioned in high potential markets to participate in future opportunities. The most critical dimension of quality is our performance in the area of health, safety, and the environment (HSE) and, during 2003, the Company logged one of its best years on record. After the close of the fiscal year, two of our largest customers, ExxonMobil and Royal Dutch Shell, separately recognized the Company’s land and offshore operations for leadership and excellence in HSE. Financial & Operating Review Years Ended September 30 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues① Operating Costs① Depreciation Operating Income① Income from Investments Interest Expense General and Administrative Expense① Income from Continuing Operations Net Income Diluted Earnings Per Common Share: Income from Continuing Operations Net Income 507,331 345,537 82,513 79,281 7,953 12,289 41,003 17,873 17,873 0.35 0.35 523,803 361,669 61,447 100,687 28,076 980 36,563 53,706 63,517 1.07 1.26 531,604 330,181 49,532 151,891 10,967 1,701 28,180 80,467 144,254 1.58 2.84 *$000’s omitted, except per share data. ①Certain prior year amounts have been reclassified to conform to current year classifications. (see note 1) †All data excludes discontinued operations except net income. 384,762 248,568 77,317 58,877 32,063 2,730 23,306 36,470 82,300 .73 1.64 431,741 290,048 70,092 71,601 7,422 5,389 24,629 32,115 42,788 .65 .86 479,592 322,861 58,187 98,544 45,152 336 21,299 80,790 101,154 1.60 2.00 SUMMARY FINANCIAL DATA* Cash** Working Capital** Investments Plant, Property, and Equipment, Net** Total Assets Long-term Debt Shareholders’ Equity Capital Expenditures** *$000’s omitted. ** Excludes discontinued operations. RIG FLEET SUMMARY Drilling Rigs – United States Land – FlexRigs United States Land – Conventional United States Offshore Platform International Total Rig Fleet Rig Utilization Percentage – United States Land – FlexRigs United States Land – Conventional United States Land – All Rigs United States Offshore Platform International 38,189 108,913 158,770 1,058,205 1,415,835 200,000 917,251 246,301 46,883 105,852 150,175 897,445 1,227,313 100,000 895,170 312,064 128,826 223,980 203,271 650,051 1,300,121 50,000 1,026,477 184,668 107,632 179,884 307,425 526,723 1,200,854 50,000 955,703 65,820 21,758 82,893 240,891 553,769 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 43 40 12 32 127 97 67 81 51 39 26 40 12 33 111 96 78 84 83 51 13 36 10 37 96 100 96 97 98 56 6 32 10 40 88 99 82 85 94 47 6 34 10 39 89 79 68 69 95 53 6 30 10 44 90 100 94 94 99 88 353,355 228,958 48,291 76,106 11,746 34 15,636 48,801 84,186 .97 1.67 27,963 65,802 323,510 392,489 987,432 — 780,580 114,626 — 29 9 39 77 — 99 99 63 91 274,208 184,703 39,592 49,913 5,992 678 15,222 25,844 72,566 .52 1.46 16,892 48,128 229,809 329,377 786,351 — 645,970 83,411 — 30 11 36 77 — 88 88 70 85 229,316 158,815 37,364 33,137 11,279 407 14,019 18,464 9,751 .38 .20 19,543 50,038 156,908 286,678 707,061 — 562,435 89,709 — 30 11 35 76 — 73 73 66 84 206,991 148,210 31,038 27,743 6,944 385 14,126 13,216 24,971 .27 .51 29,447 76,238 87,414 235,067 624,827 — 524,334 59,379 — 36 11 29 76 — 66 66 79 88 167,956 114,858 29,397 23,701 9,494 925 12,422 8,978 24,550 .18 .50 61,656 104,085 84,945 209,877 610,935 3,600 508,927 27,823 — 31 11 29 71 — 48 48 70 68 Helmerich & Payne, Inc. FORM 10-K, 2003 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, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-4221 HELMERICH & PAYNE, INC. (Exact name of registrant as specified in its charter) DELAWARE 73-0679879 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification no.) UTICA AT TWENTY-FIRST STREET, TULSA, OKLAHOMA 74114 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (918) 742-5531 Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED Common Stock ($0.10 par value) New York Stock Exchange Common Stock Purchase Rights New York Stock Exchange Securities registered Pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ] At March 31, 2003, the aggregate market value of the voting stock held by non-affiliates was $1,218,694,981. Number of shares of common stock outstanding at December 15, 2003: 50,168,655. 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, 2003 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 3, 2004 10-K Parts Parts I and II 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 UNDER THE CAPTION “RISK FACTORS” BEGINNING ON PAGE 5, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 24 THROUGH 47 OF THE COMPANY’S ANNUAL REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. 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, information technology, budgeting, insurance, cash management, and related activities. The Company’s contract drilling business is composed of three business segments: domestic land drilling, domestic offshore platform drilling and international drilling. 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 California. The Company also operated during fiscal 2003 in seven international locations: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Equatorial Guinea, and Hungary. The Company’s real estate investments are located in Tulsa, Oklahoma, where the Company maintains 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 the assets and liabilities of its 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. As a result of this transaction, Cimarex Energy Co. became a separate publicly-traded company that owned and operated the exploration and production business. The Company does not own any common stock of Cimarex Energy Co. 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 in medium to deep drilling in major gas producing basins of the United States and in drilling for oil and gas in international locations. 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 2003, the Company received approximately 68% of its consolidated revenues from the Company’s ten largest contract drilling customers. BP plc, Shell Oil Company, and ExxonMobil Corporation (respectively, “BP”, “Shell” and “ExxonMobil”), including their affiliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for BP, Shell, and ExxonMobil on a world-wide basis. Revenues from drilling services performed for BP, Shell and ExxonMobil in fiscal 2003 accounted for approximately 16%, 15% and 11%, respectively, of the Company’s consolidated revenues from continuing operations for the same period. 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 and the drilling site conditions are 1 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. 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. 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. The original six rigs were designated as FlexRig1 rigs. Subsequently, the Company built and completed 12 new FlexRig2 rigs. During fiscal 2001, the Company announced that it would build an additional 25 new FlexRigs. 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 that enables simultaneous crew activities. All 25 of these FlexRigs were completed by June of 2003. During fiscal 2003, the Company began constructing seven more FlexRig3s at an approximate cost of $11,250,000 each. Two of the seven were completed in fiscal year 2003. The other five will be completed by March 2004. All FlexRigs 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 2003. 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. D O M E S T I C L A N D D R I L L I N G The Company believes it is a major land drilling contractor in the domestic market. At the end of September 2003, the Company had 83 of its land rigs available for work in the United States. The 17-rig increase from fiscal 2002 to 2003 was due to the delivery of 19 new FlexRigs and the transfer of two rigs to the Company’s international operations. The Company’s land operations contributed approximately 53% of the Company’s consolidated revenues during fiscal 2003. Rig utilization in fiscal 2003 was 81%, down from 84% in fiscal 2002. However, the 22,588 activity days in fiscal 2003 were up from the fiscal 2002 total of 17,478 due to the increase in rig count. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 95% during fiscal 2003 while the Company’s conventional rigs had an average utilization rate of approximately 58%. At the close of fiscal 2003, 68 land rigs were working out of 83 available rigs. D O M E S T I C O F F S H O R E P L A T F O R M D R I L L I N G The Company’s offshore platform operations contributed approximately 22% of the Company’s consolidated revenues during fiscal 2003. Rig utilization in fiscal 2003 was 51%, down from 83% in fiscal 2002. At the end of this fiscal year, the Company had five of its 12 offshore platform rigs under contract and it continued to work under management contracts for three customer-owned rigs. It is likely during the first six months of calendar 2004 that two platform rigs will be placed on standby status and will receive lower standby rates. I N T E R N A T I O N A L D R I L L I N G General The Company’s international drilling operations began in 1958 with the acquisition of 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. The Company’s international operations contributed approximately 21% of the Company’s consolidated revenues during fiscal 2003. Rig utilization in fiscal 2003 was 39%, down from 51% in fiscal 2002. Venezuela Venezuelan operations continue to be a significant part of the Company’s operations. During fiscal 2003, the Company sold three workover/drilling rigs, leaving the Company with 11 land drilling rigs in Venezuela at the end of fiscal 2003. The Company worked exclusively for the Venezuelan state petroleum company during fiscal 2003, and revenues from this work accounted for approximately 6% of the Company’s consolidated revenues during the fiscal year. The Company had six rigs working in Venezuela at the end of fiscal 2003. The Company’s rig utilization rate in Venezuela has decreased from approximately 41% during fiscal 2002 to approximately 33% in fiscal 2003. Even though the Company is, at this time, unable to predict future fluctuations in its utilization rates during fiscal 2004, the Company believes that the prospects are good for returning at least two of its idle rigs back to work in Venezuela during fiscal 2004. Ecuador At the end of fiscal 2003, the Company owned eight rigs in Ecuador. The Company’s utilization rate was approximately 85% during fiscal 2003, down from approximately 93% in fiscal 2002. Revenues generated by Ecuadorian drilling operations contributed approximately 10% of the Company’s consolidated revenues during fiscal 2003. The Ecuadorian drilling contracts are primarily with large international oil companies. 2 3 Colombia During fiscal 2003, the Company owned three drilling rigs in Colombia. The Company’s utilization rate in Colombia was approximately 21% during fiscal 2003, down from approximately 31% in fiscal 2002. The revenues generated by Colombian drilling operations contributed approximately 1% of the Company’s consolidated revenues in fiscal 2003. At the end of fiscal 2003, the Company was operating one rig in Colombia, which has since ceased operations. Other Locations In addition to its operations in Venezuela, Ecuador and Colombia, in fiscal 2003, the Company owned six rigs in Bolivia and two rigs in Argentina. At the end of fiscal 2003, no rigs were operating in Bolivia or Argentina. However, as of the end of November, 2003, one rig was operating in each of Bolivia and Argentina. During fiscal 2003, the Company continued operations under a management contract for a customer-owned platform rig located offshore Equatorial Guinea. Also, during the fiscal year, the Company moved one FlexRig each to Hungary and Chad. The rig in Hungary began operations in July 2003 and the rig in Chad is currently expected to commence drilling operations in December of 2003. 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 15 separate buildings, with parking and other common facilities covering an area of approximately 30 acres. The Company in fiscal 2003, with the assistance of an architectural consulting firm, has determined that the gross usable area within the buildings of the shopping center is 441,588 square feet, composed of retail space of 382,801 usable square feet, office space of 39,400 usable square feet, storage space of 2,404 usable square feet and common area space of 16,983 usable square feet. The Company’s real estate operations occupy approximately 4,140 square feet of general office and storage space. In calendar 2003, the Company renovated and converted a vacated department store to multi-tenant retail, office, and storage space. Occupancy in the shopping center increased from 80% in fiscal 2002 to 85% in fiscal 2003 with the addition of a children’s clothing store located within the newly-renovated space. Following the demolition of an eight-story medical office building in 2002, the Company undertook a redevelopment of that site, adding two new restaurant locations. Two new upscale restaurants containing 8,305 and 7,143 square feet, respectively, have been completed and are operating at such locations. At the end of the 2003 fiscal year, the Company owned 11 of a total of 73 units in The Yorktown, a 16-story luxury residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to Utica Square Shopping Center. Seven 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 has leased from a third party approximately 114,000 square feet of office space and intends to relocate its principal executive offices to such space by the end of calendar 2003. Following the relocation, the Company intends, during calendar 2004, to raze the former headquarters building. Thereafter, the Company will investigate future development opportunities for this site. The Company 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 98%, which is down from 100% in fiscal 2002. The Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses. In July of 2003, the Company sold approximately 14.91 acres of undeveloped land in Southpark. The sales price totaled approximately $2.2 million. Southpark is located in a high growth area of southeast Tulsa and is suitable for mixed commercial and light industrial development. Subsequent to such sale and at the end of fiscal 2003, the Company owned approximately 220 acres in Southpark consisting of approximately 207 acres of undeveloped real estate and approximately 13 acres of multi-tenant warehouse area. The warehouse area is known as Space Center East and consists of two warehouses, one containing approximately 90,000 square feet and the other containing approximately 112,500 square feet. Present occupancy is 96%, which is up from 93% in fiscal 2002. The Company believes that a high quality office park, with peripheral commercial, office/warehouse, and hotel sites, is the best development use for the remaining land. However, no development plans are currently pending. The Company 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 increased from 80% to 84% during fiscal 2003. The Company also owns a 12 building complex, consisting of approximately 204,600 square feet of office/warehouse space, called Tulsa Business Park. The project is located south and east of the Space Center facility, separated by a city street, and contains approximately 12 acres. During fiscal 2003, occupancy has decreased from 96% to 86%. The Company 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 2003, 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 2003, occupancy has remained at 17%. F I N A N C I A L Information relating to Revenue and Operating Profit by Business Segments may be found on pages 72 through 74 of the Company’s Annual Report. E M P L O Y E E S The Company had 2,929 employees within the United States (10 of which were part-time employees) and 1,008 employees in international operations as of September 30, 2003. R I S K F A C T O R S In addition to the risks and factors discussed elsewhere in this report, the Company cautions that the following “Risk Factors” could affect its actual results in the future. 1. Competition Competition in the Contract Drilling Business 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, leading to increased price competition. 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 4 5 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. Competition in the Real Estate Business 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. 2. Operating Risks 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. 3. Indemnification and Insurance Coverage 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 2004. No assurance can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2004 or that insurance coverage will continue to be available at rates considered reasonable. Additionally, no assurance can be given that the Company’s insurance and indemnification arrangements will adequately protect it against all liabilities that could result from the hazards of its drilling operations. Incurring a liability for which the Company is not fully insured or indemnified could materially affect the Company’s results of operations. 4. Volatility of Oil and Gas Prices 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 depress the level of exploration and production activity and result in a corresponding decline in demand for the Company’s services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for the Company’s services could have a material and adverse effect on the Company. 5. International Uncertainties and Local Laws 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. Although the Company attempts to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2003, approximately 21% of the Company’s consolidated revenues were generated from the international contract drilling business. Approximately 86% of the international revenues were from operations in South America and approximately 87% of South American revenues were from Venezuela and Ecuador. 6. Currency Risk General 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. Based upon current information, the Company believes that exposure to potential losses from currency devaluation is minimal in Colombia, Ecuador, Bolivia, and Equatorial Guinea. 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. Argentina In 2002, Argentina suffered a 60% devaluation of the peso. As a consequence, the Company secured agreements with its customers that limited 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. The Company did not experience Argentine currency losses in fiscal 2003. Venezuela The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. 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 significance of this arrangement is that even though the dollar-based invoices may be paid in bolivars, the Company, historically, has usually been able to convert the bolivars into U.S. dollars in a timely manner and thus avoid, in large measure, devaluation losses pertaining to the dollar-based invoices. However, this arrangement is effective only in the absence of exchange controls. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 bolivars to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the Central Bank. As a result of these exchange controls, the Company has been unable since January 2003 to convert its bolivar cash balances into U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was approximately 14 billion bolivars or approximately $8.8 million. Historically, the Company has kept bolivar cash balances at necessary minimum levels. Absent existing exchange controls, the Company would have converted approximately 95% of the bolivars (13.3 billion bolivars) into $8.3 million. 6 7 As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivars into U.S. dollars. In compliance with such regulations, the Company on October 1, 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which effectively will convert 14 billion bolivars into U.S. dollars. The Company is unable to predict if or when this request will be approved. As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. From August of 2002 to August of 2003, there was a 13% devaluation of the bolivar. As a result, the Company experienced a $624,000 devaluation loss. This 13% devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal 2003 and if a 25% to 50% devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $3,200,000 to $5,100,000. In late August 2003, the Venezuelan state petroleum company agreed, on a prospective basis, to pay a portion of the Company’s dollar-based invoices in U.S. dollars. While this is a positive development in light of the existing exchange controls, there is no guarantee as to how long this arrangement will continue. Were this agreement to end, the Company would revert back to receiving these payments in bolivars and thus increase bolivar cash balances and exposure to devaluation. 7. Governmental Instability in Venezuela Governmental instability continues to exist in Venezuela. In the event that extended labor strikes occur 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. at September 30, 2003, of which $25 million is due in 2007 and the remaining $175 million is due 2009 through 2014. The average interest rate during the next four years on this debt is 6.3%, after which it increases to 6.4%. The fair value of this debt at September 30, 2003 was approximately $226.5 million. At September 30, 2003, the Company had in place a committed unsecured line of credit totaling $125,000,000. There was $30,000,000 borrowed against the line of credit and $13,747,260 of outstanding letters of credit as of September 30, 2003. The Company’s line of credit interest rate is based on LIBOR plus 87 to 112.5 basis points based on the Company’s EBITDA to net debt ratio. As the Company draws on this line of credit, it is 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 2003, interest rates could rise for a number of various reasons in the future and increase the Company’s total interest expense, depending upon the amount borrowed against the credit line. 10. Equity Price Risk At September 30, 2003, the Company owned stocks in other publicly held companies with a total market value of $169,546,000. These securities are subject to a wide variety 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., 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. 11. Reliance on Small Number of Customers In fiscal 2003, the Company received approximately 68% of its consolidated revenues from the Company’s ten largest contract drilling customers and approximately 42% of its consolidated revenues from the Company’s three largest customers (including their affiliates). The Company believes that its relationship with all of these customers is good; however, the loss of one or more of its larger customers would have a material adverse effect on the Company’s results of operations. 8. Government Regulation and Environmental Risks 12. Key Personnel 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 enforceability 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. 9. Interest Rate Risk In 2002, the Company entered into a $200,000,000 intermediate-term unsecured debt obligation with staged maturities from five to 12 years with varying fixed interest rates for each maturity series. There was $200 million outstanding The Company utilizes highly skilled personnel in operating and supporting its businesses. In times of high utilization, it can be difficult to find qualified individuals. Although to date the Company’s operations have not been materially affected by competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact the Company’s results of operations. 13. Changes in Technologies Although the Company takes measures to ensure that it uses advanced oil and natural gas drilling technology, changes in technology or in the Company’s competitors’ equipment could make the Company’s equipment less competitive or require significant capital investments to keep its equipment competitive. 14. Concentration of Credit The concentration of the Company’s customers in the energy industry could cause them to be similarly affected by changes in industry conditions and, as a result, could impact the Company’s exposure to credit risk. The Company cannot offer assurances that losses due to uncollectible receivables will be consistent with expectation. 8 9 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, 2003: Location FLEXRIGS Texas Texas Texas Texas Texas Wyoming Wyoming Texas Texas Texas Texas Texas Texas Texas Texas Oklahoma Texas Texas Texas Texas Texas Colorado Texas Texas Texas Texas Texas Louisiana Oklahoma Texas Texas Oklahoma Louisiana Texas Texas Texas Texas Texas Rig 164 165 166 169 178 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 Optimum Depth Rig Type Drawworks: Horsepower 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 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 SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location Texas Texas Texas Texas Texas HIGHLY MOBILE RIGS Oklahoma Texas Wyoming Texas Texas Texas Texas Texas Texas Texas Wyoming CONVENTIONAL RIGS Texas Oklahoma Texas Texas Texas Louisiana Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma Texas Louisiana Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Louisiana Rig 232 233 234 235 236 158 156 159 141 142 143 145 155 146 147 154 110 96 118 119 120 162 80 89 92 94 98 122 79 97 99 137 149 191 192 170 72 73 125 134 136 Optimum Depth Rig Type Drawworks: Horsepower 18,000 18,000 18,000 18,000 18,000 10,000 12,000 12,000 14,000 14,000 14,000 14,000 14,000 16,000 16,000 16,000 12,000 16,000 16,000 16,000 16,000 18,000 20,000 20,000 20,000 20,000 20,000 16,000 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 AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) SCR Mechanical Mechanical Mechanical Mechanical Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR (Heli Rig) SCR SCR SCR SCR SCR 1,500 1,500 1,500 1,500 1,500 900 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,500 700 1,000 1,200 1,200 1,200 1,500 1,500 1,500 1,500 1,500 1,500 1,700 2,000 2,000 2,000 2,000 2,000 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 10 11 Location Texas Louisiana Louisiana Texas Rig 157 161 163 139 OFFSHORE PLATFORM RIGS Texas Louisiana Gulf of Mexico Gulf of Mexico Louisiana Louisiana Louisiana Louisiana Louisiana Gulf of Mexico Gulf of Mexico Gulf of Mexico 108 91 203 205 206 100 105 106 107 201 202 204 Optimum Depth Rig Type Drawworks: Horsepower 30,000 30,000 30,000 30,000+ 18,000 20,000 20,000 20,000 20,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 SCR SCR SCR SCR Self-Erecting Conventional Self-Erecting Tension-leg Self-Erecting Conventional Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 3,000 3,000 3,000 3,000 1,500 3,000 2,500 2,000 1,500 3,000 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of the Company’s domestic drilling rigs for the periods indicated: Years ended September 30, Number of rigs owned at end of period Average rig utilization rate during period* 1999 50 75% 2000 48 87% 2001 59 97% 2002 78 83% 2003 95 77% *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, 2003: Location Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Hungary Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 23 132 176 121 117 138 190 168 140 148 160 113 115 116 127 128 129 150 153 Optimum Depth Rig Type Drawworks: Horsepower 18,000 18,000 18,000 20,000 26,000 26,000 26,000 18,000 10,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000+ SCR (Heli Rig) SCR SCR SCR SCR SCR SCR SCR (FlexRig1) Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 1,500 1,500 1,500 1,700 2,500 2,500 2,000 1,500 900 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of the Company’s international drilling rigs for the periods indicated: Years ended September 30, Number of rigs owned at end of period Average rig utilization rate during period*† 1999 39 53% 2000 40 47% 2001 37 56% 2002 33 51% 2003 32 39% * 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. Location Argentina Argentina Bolivia Bolivia Bolivia Bolivia Bolivia Bolivia Chad Colombia Colombia Colombia Ecuador Rig 174 177 171 172 173 123 151 175 167 133 135 152 22 Optimum Depth Rig Type Draw-Works: Horsepower R E A L E S T A T E O P E R A T I O N S 30,000 30,000 16,000 16,000 20,000 26,000 30,000 30,000 18,000 30,000 30,000 30,000+ 18,000 SCR SCR Mechanical Mechanical Mechanical SCR SCR SCR SCR (FlexRig1) SCR SCR SCR SCR (Heli Rig) 3,000 3,000 1,000 1,000 2,000 2,100 3,000 3,000 1,500 3,000 3,000 3,000 1,700 See Item 1. BUSINESS, pages 4 through 5 of the Company’s Annual 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 42 of the Company’s Annual 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 manage- ment, 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. 12 13 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. The Company paid a cash dividend of $.080 per share on December 1, 2003, to stockholders of record on November 14, 2003. Payment of future dividends will depend on earnings and other factors. As of December 15, 2003, there were 1,017 record holders of the Company’s common stock as listed by 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 transfer agent’s records. 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, 80 Chairman of the Board Director since 1949; Chairman of the Board since 1960 Hans Helmerich, 45 President and Chief Executive Officer Director since 1987; President and Chief Executive Officer since 1989 George S. Dotson, 62 Vice President Director since 1990; Vice President since 1977 and President and Chief Operating Officer of Helmerich & Payne International Drilling Co. since 1977 Douglas E. Fears, 54 Vice President and Chief Financial Officer since 1988 Steven R. Mackey, 52 Vice President, Secretary and General Counsel Secretary since 1990; Vice President and General Counsel since 1988 Gordon K. Helm, 50 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 2002 High* Low* $ 35.25 $ 24.70 41.31 43.24 38.35 27.70 33.70 28.90 2003 High Low $ 30.23 $ 23.45 28.94 32.80 30.30 22.60 24.72 25.70 * Market prices for 2002 are prior to distribution of 100% of common stock of Cimarex Energy Co. (See Note 2 of the Consolidated Financial Statements). The Registrant paid quarterly cash dividends during the past two years as shown in the following table: Quarter First Second Third Fourth Paid per Share Fiscal Total Payment Fiscal 2002 $0.075 0.075 0.075 0.080 2003 $0.080 0.080 0.080 0.080 14 2002 2003 $3,738,220 $4,000,982 3,739,680 3,743,587 3,999,597 4,002,239 4,002,971 4,009,076 S U M M A R Y O F A L L E X I S T I N G E Q U I T Y C O M P E N S A T I O N P L A N S The following chart sets forth information concerning the compensation plans under which equity securities of the Company are authorized for issuance as of September 30, 2003. Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (a) (b) (c) Plan Category: Equity compensation plans approved by security holders (1) 4,327,388 $ 21.408 1,596,950 Equity compensation plans not approved by security holders (2) Total – 4,327,388 – $ 21.408 – 1,596,950 (1) Includes the 1990 Stock Option Plan, the 1996 Stock Incentive Plan and the 2000 Stock Incentive Plan of the Company. (2) The Company does not maintain any equity compensation plans that have not been approved by the stockholders. 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 Results of Operations and Financial conditions contained at pages 24 through 47 of the Company’s Annual Report. On September 30, 2002, the Company spun off Cimarex Energy Co. 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 $439,118 $416,272 $542,571 $551,879 $515,284 Income from continuing operations 32,115 36,470 80,467 53,706 17,873 1999 2000 2001 2002 2003 (in thousands) Income from continuing operations per common share: Basic Diluted Total assets Long-term debt Cash dividends declared per common share 0.28 50,000 0.65 0.65 0.74 0.73 1.61 1.58 1.08 1.07 0.36 0.35 1,073,465 1,200,854 1,300,121 1,227,313 1,415,835 50,000 0.285 50,000 100,000 200,000 0.30 0.31 0.32 15 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 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 Information required by this item may be found on pages 24 through 47 of the Company’s Annual 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 the Company’s Annual 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 43- 45 45 - 46 46 - 47 47 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 49 through 75 of the Company’s Annual 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. I T E M 9 A. 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. As of the end of the period covered by 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 operation 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 appro- priate 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 changes in the Company’s internal control over financial reporting during the Company’s last fiscal quarter of 2003 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 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 3, 2004, to be filed with the Commission not later than 120 days after September 30, 2003. The information required by this Item with respect to the Company’s Executive Officers appears on page 14 of the Company’s Annual Report. The Company has adopted a Code of Ethics for Principal Executive Officers and Senior Financial Officers. The text of such Code is located on the Company’s website under “Investor Relations - Corporate Governance.” The Company’s Internet address is www.hpinc.com. 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 3, 2004, to be filed with the Commission not later than 120 days after September 30, 2003. 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 A N D M A N A G E M E N T 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 This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2004, to be filed with the Commission not later than 120 days after September 30, 2003. 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 3, 2004, to be filed with the Commission not later than 120 days after September 30, 2003. I T E M 1 4 . P R I N C I P A L A C C O U N T A N T F E E S A N D S E R V I C E S This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2004, to be filed with the Commission not later than 120 days after September 30, 2003. 16 17 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 the Company’s Annual 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, 2003, 2002 and 2001 48 49 Consolidated Balance Sheets at September 30, 2003 and 2002 50-51 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2003, 2002 and 2001 Consolidated Statements of Cash Flows for the Years Ended September 30, 2003, 2002 and 2001 Notes to Consolidated Financial Statements 52 53 54-75 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. 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 incorporat- ed 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 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 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. *10.14 Form of Change of Control Agreement for Helmerich & Payne, Inc. 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. 10.15 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 reference 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. 10.16 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. 10.17 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221. 10.18 Office Lease dated May 30, 2003, between K/B Fund IV and Helmerich & Payne, Inc. 18 19 13. The Company’s Annual Report to Stockholders for fiscal 2003. 21. List of Subsidiaries of the Company. 23.1 Consent of Independent Auditors. 31.1 Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Compensatory plan or arrangement (b) Reports on Form 8-K /s/ Edward B. Rust, Jr. By Edward B. Rust, Jr., Director Date: December 23, 2003 /s/ John D. Zeglis By John D. Zeglis, Director Date: December 23, 2003 /s/ Paula Marshall-Chapman By Paula Marshall-Chapman, Director Date: December 23, 2003 /s/ Douglas E. Fears /s/ Douglas E. Fears By Douglas E. Fears, (Principal Financial Officer) Date: December 23, 2003 /s/ Gordon K. Helm By Gordon K. Helm, Controller (Principal Accounting Officer) Date: December 23, 2003 The Company filed two reports on Form 8-K during the last quarter of fiscal 2003 as follows: (cid:1) Form 8-K dated July 15, 2003, disclosing certain revisions to the Helmerich & Payne, Inc. C E R T I F I C A T I O N Employees Retirement Plan. (cid:1) Form 8-K dated July 24, 2003, 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 2003 earnings. 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, 2003 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, 2003 /s/ George S. Dotson By George S. Dotson, Director Date: December 23, 2003 /s/ W.H. Helmerich, III By W. H. Helmerich, III, Director Date: December 23, 2003 /s/ Glenn A. Cox By Glenn A. Cox, Director Date: December 23, 2003 /s/ Hans Helmerich By Hans Helmerich, Director and CEO Date: December 23, 2003 /s/ L. F. Rooney, III By L. F. Rooney, III, Director Date: December 23, 2003 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 Registrant as of, and for, the periods presented in this annual report; 4. The Registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures [as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)] for the Registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and 20 21 5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. /s/ Hans Helmerich Hans Helmerich, Chief Executive Officer December 23, 2003 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 Registrant as of, and for, the periods presented in this annual report; 4. The Registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures [as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)] for the Registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the peri- od in which this annual report is being prepared; b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and 5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over finan- cial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, sum- marize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. /s/ Douglas E. Fears Douglas E. Fears, Chief Financial Officer December 23, 2003 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, 2003 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, 2003 /s/ Douglas E. Fears Douglas E. Fears Chief Financial Officer December 23, 2003 22 23 Management’s Discussion & Analysis of Management’s Discussion & Analysis of Results of Operations and Financial Condition Results of Operations and Financial Condition R I S K F A C T O R S A N D F O RWA R D - L O O K I N G S TAT E M E N T S 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 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 and those factors discussed under Risk Factors beginning on page 5 of the Company’s Annual Report 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. 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 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. The Company and its subsidiaries continue to own and operate contract drilling and real estate businesses, while Cimarex Energy Co. is a separate, publicly traded company that owns and operates an exploration and production business. The Company does not own any common stock of Cimarex Energy Co. (See note 2 of the Consolidated 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 2003 was $17,873,000 ($0.35 per share), compared with net income of $63,517,000 ($1.26 per share) in 2002, and $144,254,000 ($2.84 per share) in 2001. Included in net income was income from discontinued operations of $9,811,000 ($0.19 per share) in 2002, and $63,787,000 ($1.26 per share) in 2001. 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 $3,346,000 ($0.07 per share) in 2003, $15,206,000 ($0.30 per share) in 2002, and $691,000 ($0.01 per share) 24 25 in 2001. Also included in net income is the Company’s portion of income or loss from its equity affiliates, Atwood Oceanics, Inc. and a 50-50 joint venture with Atwood called Atwood Oceanics West Tuna Pty. Ltd. (dissolved in 2003). From equity affiliates, the Company recorded a loss of $0.03 per share in 2003, and net income of $0.06 and $0.04 per share in 2002 and 2001, respectively. Consolidated revenues were $515,284,000 in 2003, $551,879,000 in 2002, and $542,571,000 in 2001. From 2001 to 2003 revenues attributable to contract drilling operations fell slightly each year. However, total revenues increased from 2001 to 2002 due to a larger gain realized on the sale of a portion of the Company’s equity portfolio. U.S. land revenues rose steadily from 2001 to 2003, while international drilling revenues declined significantly during the same period. Although U.S. offshore platform revenues were relatively flat from 2001 to 2002, there was a drop of approximately 15 percent in offshore platform revenues from 2002 to 2003. Revenue reductions in the offshore platform business were mainly due to a drop in rig utilization to 51 percent in 2003, from 83 percent in 2002, and 98 percent in 2001. The increase in U.S. land revenues was fueled by the Company’s increasing rig fleet due to the construction of FlexRigs over the three-year period. The average number of U.S. land rigs available was 76 in 2003, 57 in 2002, and 42 in 2001. Although rig availability increased, rig utilizations fell for the Company’s U.S. land rig fleet to 81 percent in 2003, compared with 84 percent in 2002, and 97 percent in 2001. International rig revenues declined as rig utilizations in that sector fell to 39 percent in 2003, from 51 percent in 2002, and 56 percent in 2001. The Company’s international rig utilization was impacted by significant reductions in activity in Venezuela and Colombia since 2001. Cutbacks in drilling budgets for the government- owned oil company, PDVSA, reduced drilling in Venezuela. In Colombia, completion of development of a customer’s major oilfield has dramatically reduced drilling activity there. Revenues from investments were $7,953,000 in 2003, $28,076,000 in 2002, and $10,967,000 in 2001. Included in revenues was the aggregate of pre-tax gains, losses, and write-downs relating to the Company’s portfolio of equity securities which were $5,529,000 in 2003, $24,820,000 in 2002, and $1,189,000 in 2001. Interest and dividend income fell in each year due to reduced cash positions, lower interest rates, and a reduction in the Company’s equity portfolio. Total interest and dividend income was $2,467,000 in 2003, $3,624,000 in 2002, and $9,128,000 in 2001. Direct operating costs in 2003 were $345,537,000 or 68 percent of operating revenues, compared with $361,669,000 or 69 percent of operating revenues in 2002, and $330,181,000 or 62 percent of operating revenues in 2001. Direct operating costs were lower as a percentage of revenues in 2001, primarily due to the higher average revenue per day and lower daily direct operating costs per day during 2001 in the U.S. land rig segment. Industry rig activity was relatively high in 2001, resulting in higher dayrates for the Company. Depreciation expense was $82,513,000 in 2003, $61,447,000 in 2002, and $49,532,000 in 2001. Depreciation rose significantly over the two-year period as the Company placed into service 13 new rigs in 2002, and 19 new rigs in 2003. The Company anticipates depreciation expense to increase again during 2004, as a full year of depreciation expense is incurred on rigs placed into service in 2003, and as new rigs are constructed and employed in the field. 26 27 The Company’s methodology of reporting business segments and general and administrative expenses has been changed in 2003. This change was driven by last year’s spin-off of our Exploration and Production Company and to better reflect the way the Company manages its contract drilling businesses. The number of contract drilling business segments reported have increased to three to reflect the Company’s U.S. offshore platform operations separately from the U.S. land rig operations. Formerly, the combined U.S. segments were reported as one segment. It is important to note that total operating profit for U.S. operations and the international contract drilling segment has not changed. U.S. Land and Offshore Platform segments have simply been separated. Expenses within the Company’s contract drilling business segments have been broken out to delineate direct operating costs from associated general and administrative costs. Formerly, both costs were included in operating costs on the consolidated statements of income. The associated general and administrative costs of the contract drilling segments have been reclassified to general and administrative expense on the consolidated statements of income. These general and administrative costs are still included in the applicable contract drilling segment. No other numbers on the consolidated statements of income were changed or affected by this reclassification. With the reclassifications, general and administrative expenses totaled $41,003,000 for 2003, $36,563,000 for 2002, and $28,180,000 for 2001. The 30 percent increase from 2001 to 2002 was primarily the result of increases in employee benefits relating to pension, medical insurance, and 401(k) matching. Employee salaries and bonuses also contributed to the increase, as well as increases in property and casualty insurance costs. With the construction of the FlexRigs, training expenses were also a contributor to the increase from 2001 to 2002. General and administrative expenses rose again from 2002 to 2003 due to additional increases in pension and medical insurance expense, along with increases in property and casualty insurance costs. Interest expense rose to $12,289,000 in 2003, compared with $980,000 in 2002, and $1,701,000 in 2001. The Company issued a total of $200,000,000 of intermediate-term debt, half of which was placed just prior to the end of fiscal year 2002, and the other half placed at the very beginning of fiscal year 2003. Additionally, the Company also drew on its bank line of credit during 2003, with $30,000,000 drawn at the end of the year. The provision for income taxes totaled $14,649,000 in 2003, $40,573,000 in 2002, and $54,689,000 in 2001. Effective income tax rates on income from continuing operations were 43 percent in 2003, 44 percent in 2002, and 41 percent in 2001. The increase in effective tax rates 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. There was less of such an effect in 2003, but international income at higher effective tax rates combined with the impact of state income taxes, kept the overall Company tax rate at a relatively high level. 28 29 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 3 A N D 2 0 0 2 U.S. LAND OPERATIONS Revenues Intersegment elimination Direct operating expenses Intersegment elimination General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 2003 2002 % Change (in thousands, except operating statistics) $273,993 – 201,398 – 9,304 44,726 $232,446 (809) 165,394 (648) 10,087 26,311 $ 18,565 $ 30,493 22,588 $ 11,436 $ 8,221 $ 3,215 83 81% 17,478 $ 12,397 $ 8,561 $ 3,836 66 84% 17.9% – 21.8 – (7.8) 70.0 (39.1) 29.2% (7.8) (4.0) (16.2) 25.8 (3.6) margins did not continue at those levels during 2003 after contracts expired. The Company’s increase in rig capacity was brought about by its FlexRig3 construction program that began during 2002 and extended through 2003. During 2003, 19 FlexRig3s were completed and put into service. Two first generation FlexRig’s were sent overseas for work in Hungary and Chad. As a result of the construction program, the Company’s investment in drilling equipment rose significantly, thereby resulting in an increase in depreciation expense. Although the Company will have more rigs available for service next year, and although industry fundamentals are positive going in to 2004, a drop in dayrates or rig utilization could cause U.S. land rig operating profit to decrease next year. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 3 A N D 2 0 0 2 Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. 2003 2002 % Change The Company’s operating profit in its U.S. land rig operations fell by 39 percent from 2002 to 2003, despite the fact that commodity prices were very strong during the year. Historically high crude oil and natural gas prices, and an increasing industry rig count in the United States were all strong signals for an up cycle that could benefit oil service and contract drilling companies. However, in spite of increasing rig activity, average dayrates and margins per rig day fell during the year. Even with higher industry rig counts, the additional capacity added by companies like Helmerich & Payne, along with intense rig-on-rig price competition, delayed improvements in dayrates and margins. More specifically with Helmerich & Payne, 2002 dayrates were aided by the remaining term left on some of the contracts for work relating to FlexRig2s that were completed and commenced work during 2001. Those relatively high dayrates and U.S. OFFSHORE PLATFORM OPERATIONS (in thousands, except operating statistics) Revenues $112,633 $132,249 Direct operating expenses General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 60,589 2,939 12,799 79,301 3,451 10,809 $ 36,306 $ 38,688 2,233 $ 38,239 $ 17,822 $ 20,417 12 51% 3,286 $ 30,424 $ 16,263 $ 14,161 12 83% (14.8)% (23.6) (14.8) 18.4 (6.2) (32.0)% 25.7 9.6 44.2 0.0 (38.6) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts. 30 31 During the year, the Company continued to experience a reduction in activity days and rig utilization in its U.S. offshore platform rig operations. Total revenue and revenue per day during 2003 were aided by the recognition of revenue due to early termination of contracts. During the fourth quarter of 2003, one platform rig was stacked and two rigs that were working at full dayrate were changed to standby status, thereby likely causing a reduction of the first quarter 2004 operating profit for the U.S. offshore rig segment of approximately 50 percent from that of the fourth quarter of 2003. Capital expenditures were reduced dramatically due to the fact that there were no new platform rigs under construction during 2003, whereas two new platform rigs were completed during 2002. It is anticipated that during 2004, the U.S. offshore platform market will continue to be soft, unless and until commodity pricing or other circum- stances significantly increase demand for platform rigs. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 3 A N D 2 0 0 2 INTERNATIONAL OPERATIONS Revenues Direct operating expenses General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 2003 2002 % Change (in thousands, except operating statistics) $109,812 81,461 3,110 20,092 $ 5,149 4,515 $ 19,603 $ 14,140 $ 5,463 32 39% $151,392 115,294 2,634 20,336 $ 13,128 5,956 $ 21,161 $ 14,599 $ 6,562 33 51% (27.5)% (29.3) 18.1 (1.2) (60.8) (24.2)% (7.4) (3.1) (16.7) (3.0) (23.5) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts. Rig activity, revenues, and operating profit in the Company’s international operations declined from 2002 to 2003. The general softness in the international markets was broad based and resulted in lower utilizations in each of the countries in which the Company operated during the 2002-2003 period. The Company’s Venezuelan operations, where the largest number of Company international rigs are located, were also hampered by an attempted coup, which resulted in a strike by workers at PDVSA, the government-owned oil company. During 2002, the Company recorded an estimated devaluation loss totaling $1,200,000 in Argentina when that country experienced a dramatic economic collapse. As a result of the collapse, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos. During 2003, the Company was able to reduce its 2002 estimated loss by approximately $980,000 relating to the Argentina currency devaluation. 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. Devaluation losses for Venezuelan operations totaled $624,000 in 2003 and $4,393,000 in 2002. The Company anticipates devaluation losses in Venezuela during 2004, but is unable to predict the extent of the devaluation. If 2004 rig activity levels are similar to 2003, and if a 25 percent to 50 percent devaluation would occur, the Company could experience potential devaluation losses ranging from approximately $3,200,000 to $5,100,000. (See MD&A section entitled Foreign Currency Exchange Rate Risk for important details regarding potential devaluation losses.) 32 33 In addition to potential devaluation, next year’s average dayrate and profit margin per rig, as well as rig utilizations are difficult to predict and, while not expected to decline during 2004, are subject to unpredictable markets that could produce significant volatility. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 3 A N D 2 0 0 2 REAL ESTATE Revenues Direct operating expenses Depreciation Operating profit 2003 $10,893 1,789 2,535 $ 6,569 2002 (in thousands) $ 8,525 1,617 1,844 $ 5,064 % Change 27.8% 10.6 37.5 29.7 Operating profit increased by approximately 30 percent from 2002 to 2003 in the Company’s Real Estate division, primarily due to the sale of approximately 15 acres of raw land from the Company’s Southpark investment. Pre-tax profit from the sale of land was approximately $2.2 million. Depreciation expense increased in 2003 due to the accelleration of depreciation on the Company’s headquarters building, which will be razed in 2004. Overall combined occupancy and resulting revenues generated from all the other real estate properties did not materially fluctuate from 2002 to 2003. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 2 A N D 2 0 0 1 U.S. LAND OPERATIONS Revenues Intersegment elimination Direct operating expenses Intersegment elimination General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 2002 2001 % Change (in thousands, except operating statistics) $232,446 (809) 165,394 (648) 10,087 26,311 $226,344 (4,487) 133,650 (2,553) 6,479 16,701 $ 30,493 $ 67,580 17,478 $ 12,397 $ 8,561 $ 3,836 66 84% 15,098 $ 14,315 $ 8,175 $ 6,140 49 97% 2.7% (82.0) 23.8 (74.6) 55.7 57.5 (54.9) 15.8% (13.4) 4.7 (37.5) 34.7 (13.4) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. U.S. land operating profit declined by 55 percent from 2001 to 2002 as overall industry rig counts declined from a cyclical high brought on by a spike in natural gas prices during 2001. The significant reduction in industry rig counts that followed during 2002 brought about lower dayrates, rig margins, and rig utilizations compared with 2001 levels. Although utilization rates declined during 2002, activity days increased due to an additional 17 rigs put into service in the U.S. land rig market. This increase was due to FlexRig construction and movement of land rigs from South American operations to the U.S. During 2002, the Company completed the final five rigs of its 12-rig FlexRig2 program commenced in 2001. It also placed eight FlexRig3s into service and added four more rigs to the U.S. fleet that were moved from South American operations. Capital spending in U.S. land rig operations 34 35 increased as the Company embarked on its FlexRig3, 25-rig construction project. As a result of capital expenditures for U.S. land operations of $236.3 million in 2002, compared with $136.7 million in 2001, depreciation expense rose by approximately 58 percent during 2002. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 2 A N D 2 0 0 1 U.S. OFFSHORE PLATFORM OPERATIONS 2002 2001 (in thousands, except operating statistics) % Change Revenues $132,249 $128,459 Direct operating expenses General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 79,301 3,451 10,809 75,810 2,962 9,576 $ 38,688 $ 40,111 3,286 $ 30,424 $ 16,263 $ 14,161 12 83% 3,572 $ 28,995 $ 15,734 $ 13,261 10 98% 3.0% 4.6 16.5 12.9 (3.5) (8.0)% 4.9 3.4 6.8 20.0 (15.3) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts. Two new offshore platform rigs were completed and placed in service during 2002 at high dayrates, but with short-term contracts. As a result, average rig revenue per day and average margins per day improved from 2001 to 2002. More than offsetting this improvement was a decline in activity days of eight percent, the beginning signs of an overall reduction in that market that continued into 2003. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 2 A N D 2 0 0 1 INTERNATIONAL OPERATIONS Revenues Direct operating expenses General and administrative expense Depreciation Operating profit Operating Statistics: Activity days Average rig revenue per day Average rig expense per day Average rig margin per day Number of owned rigs at end of period Rig utilization 2002 2001 % Change (in thousands, except operating statistics) $151,392 115,294 2,634 20,336 $ 13,128 5,956 $ 21,161 $ 14,599 $ 6,562 33 51% $170,270 120,845 2,112 18,838 $ 28,475 7,283 $ 19,683 $ 13,334 $ 6,349 37 56% (11.1)% (4.6) 24.7 8.0 (53.9) (18.2)% 7.5 9.5 3.4 (10.8) (8.9) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts. Rig utilization, total activity days, and total revenues declined from 2001 to 2002, resulting in operating profit declining by approximately 54 percent. The most significant declines in activity and profitability were in Company operations located in Colombia and Argentina. Colombia’s rig utilizations fell from 69 percent during 2001 to 31 percent during 2002. Additionally, the number of rigs available in Colombia fell from seven during the first quarter of 2001 to three by the end of 2001. Those four rigs were moved to the United States. Accordingly, profitability in Colombia declined sharply during 2002. Operating profit for Company operations in Venezuela and Argentina also declined during 2002. Devaluation losses in Venezuela were $4,393,000 in 2002, and $796,000 in 2001. (See MD&A section entitled Foreign Currency Exchange Risk for more detail regarding potential devaluation losses.) 36 37 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 2 A N D 2 0 0 1 REAL ESTATE Revenues Direct operating expenses Depreciation Operating profit 2002 $ 8,525 1,617 1,844 $ 5,064 2001 (in thousands) $ 11,018 2,419 2,284 $ 6,315 % Change (22.6)% (33.2) (19.3) (19.8) Revenues and operating profit declined from 2001 to 2002 in the Company’s Real Estate division, due to a sale of raw land which resulted in approximately $2 million of operating profit during 2001. Depreciation was higher in 2001 due to the acceleration of depreciation for a building that was razed during 2002. Earnings from ongoing leasing operations were up only slightly from 2001 to 2002. 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, impairment of long-lived assets, 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. The Company provides 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 results of operations. The Company reviews its 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 and 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, 2003, 2002, and 2001. However, should industry market conditions deteriorate from those existing currently, impairment losses could be recorded in the future. All of the Company’s 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. 38 39 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. 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 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 $246,301,000 for 2003, $312,064,000 in 2002, and $184,668,000 in 2001. Net cash provided from operating activities for those same time periods were $96,504,000 in 2003, $151,774,000 in 2002, and $127,435,000 in 2001. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $18,215,000 in 2003, $47,146,000 in 2002, and $24,438,000 in 2001. 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 seven 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 million each. During 2002, the Company completed the remaining five rigs in the FlexRig2 program and the first eight rigs in the FlexRig3 program. During 2003, the remaining 17 rigs originally planned in the FlexRig3 program were completed. Another seven FlexRig3s were scheduled for construction, two of which were completed by the end of fiscal 2003, and five are scheduled to be completed by March, 2004. The Company expects to fund its 2004 capital spending of approximately $100,000,000 with internally generated cash flows, its bank line of credit and/or from funds generated by the sale of stock from its investment portfolio. In August 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities from five 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 obli- gations 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, help fund the Company’s rig construction program and for other general corporate purposes. On September 30, 2003, the Company had a committed unsecured line of credit totaling $125 million, with short-term loans totaling $30 million and letters of credit totaling $13.7 million outstanding against the line. 40 41 The line of credit matures in July 2004 and bears interest of LIBOR + .87 percent to 1.125 percent depending on certain financial ratios of the Company. The Company must maintain certain financial ratios 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. The strength of the Company’s balance sheet is substantial, with current ratios for September 30, 2003, and 2002 at 2.2 and 2.5, respectively, and with debt to total capitalization of 18 percent and 10 percent, respectively. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2003, had a market value of $169,546,000. The Company’s investments in Atwood Oceanics, Inc., Schlumberger, Ltd., and ConocoPhillips made up almost 90 percent of the portfolio’s market value on September 30, 2003. The value of 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 2003, the Company paid a dividend of $0.32 per share, or a total of $16,015,268, 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, 2003 Number of Shares Cost Basis Market Value ( in thousands, except share amounts) Atwood Oceanics, Inc. Schlumberger, Ltd. ConocoPhillips Other Total 3,000,000 1,480,000 140,000 $ 56,655 23,511 3,486 6,303 $ 89,955 $ 71,970 71,632 7,665 18,279 $169,546 M AT E R I A L C O M M I T M E N T S The Company has no off balance sheet arrangements, as defined by SEC rules. The Company’s contractual obligations as of September 30, 2003, including payments due by year are as follows (in thousands): Total 2004 2005 2006 2007 2008 After 2008 Short-term loans (a) $ 30,000 $30,000 $ – $ – $ – $ – $ – Long-term debt (a) Operating leases (b) Purchase obligations 200,000 8,146 36,415 – 1,285 35,530 – 1,048 530 – 1,311 355 25,000 1,385 – – 1,385 – 175,000 1,732 – Total Contractual Obligations $274,561 $66,815 $ 1,578 $ 1,666 $26,385 $ 1,385 $176,732 (a) See Note 3 “Long-term Debt” to the Company’s Consolidated Financial Statements. (b) See Note 14 “Commitments and Contingencies” to the Company’s Consolidated Financial Statements. An actuarial study of the Company’s pension plan projects that no funding will be required in fiscal years 2004 or 2005. After 2005, funding requirements, if any, will be subject to returns on plan assets and other external factors. 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 Hungary, Chad, and in several South American countries, as well as 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 receipts in other countries are in U.S. dollars. Even though the Company’s contract with its customers in Argentina was in U.S. dollars, the Company recorded a devaluation loss as Argentina experienced a dramatic economic collapse during 2002. As a result of the economic collapse, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos, 42 43 resulting in the Company recording an estimated loss of $1,200,000 in 2002. The Company was able to reduce this estimated loss by approximately $980,000 during 2003. At the present time, the Company has two rigs located in Argentina, one of which will begin working during early 2004. The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, while approximately 60 percent of the Company’s invoice billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar, PDVSA typically pays all amounts owed in bolivars. The Company, historically, has usually been able to convert the bolivars received in payment of the dollar-based billings into dollars in a timely manner and thus avoid, in large measure, devaluation losses pertaining to these dollar-based invoices. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 Bolivars to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the central bank. As a result of these exchange controls, the Company has been unable since January 2003 to convert its bolivar cash balances into U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was approximately 14 billion bolivars or approximately $8.8 million. Historically, the Company has kept bolivar cash balances at necessary minimum levels to fund local operating costs. As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivars into U.S. dollars. In compliance with such regulations, the Company on October 1, 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which effectively will convert 14 billion bolivars into approximately $8.8 million. The Company is unable to predict if or when this request will be approved. From August of 2002 to August of 2003, there was a 13 percent devaluation of the bolivar. As a result, the Company experienced a $624,000 devaluation loss for 2003. This 13 percent devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal 2003 and if a 25 percent to 50 percent devaluation should occur, the Company could experience potential currency devaluation losses ranging from approximately $3,200,000 to $5,100,000. In late August 2003, the Venezuelan state petroleum company agreed, on a prospective basis, to pay a portion of the Company’s dollar-based invoices in U.S. dollars. While this is a positive development in light of the existing exchange controls, there is no guarantee as to how long this arrangement will continue. Were this agreement to end, the Company would revert back to receiving these payments in bolivars and thus increase bolivar cash balances and exposure to devaluation. 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 44 45 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 is not always purely a function of the movement of commodity prices. Interest Rate Risk. The Company’s interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based on borrowings from its commercial banks. To reduce the impact of fluctuations in interest rates, the Company maintains a portion of its total debt portfolio in fixed-rate debt. On September 30, 2003, the amount of the Company’s fixed-rate debt was approximately 87 percent of total debt. In the past, the Company has entered into financial instruments such as interest rate swaps and may consider this and other financial instruments in the future to manage the portfolio mix between fixed and floating rate debt and to mitigate the impact of changes in interest rates based on management’s assessment of future interest rates, volatility of the yield curve, and the Company’s ability to access the capital markets in a timely manner. Based on the outstanding borrowings under variable-rate debt instruments on September 30, 2003, a change in the average interest rate of 100 basis points would result in a change in net income and cash flows before income taxes on an annual basis of approximately $0.2 million and $0.3 million, respectively. The following tables provide information as of September 30, 2003 and 2002 about the Company’s interest rate risk sensitive instruments: I N T E R E S T R AT E R I S K (dollars in thousands) 2004 2005 2006 2007 2008 Fixed Rate Debt Average Interest Rate – – Variable Rate Debt $ 30,000 Average Interest Rate (a) – – – – – – – – – $ 25,000 5.5% – – – – – – After 2008 Total Fair Value @ 9/30/03 $ 175,000 $ 200,000 $ 226,500 6.4% 6.4% – – – $ 30,000 $ 30,000 (a) – (a) LIBOR plus an increment of .875% to 1.25% depending on certain financial ratios. I N T E R E S T R AT E R I S K (dollars in thousands) 2003 2004 2005 2006 2007 After 2007 Total Fair Value @ 9/30/02 Long Term Debt Fixed Rate Average Interest Rate Interest Rate Swap (b) – – – – – – – – – – – – $ 12,500 $ 87,500 $ 100,000 $ 109,700 5.5% – 6.4% 6.4% – – (b) (1,700) (b) At September 30, 2002, the Company held an interest rate swap on $50 million face value debt to receive variable interest payments based on 30-day LIBOR rates and pay fixed interest payments of 5.4% through October 27, 2003. Equity Price Risk. On September 30, 2003, the Company owned stocks in other publicly held companies with a total market value of $169,546,000. 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., 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. The total market value of the portfolio of securities was $175,668,000 at September 30, 2002. 46 47 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, 2003 and 2002, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2003. 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, 2003 2002 2001 REVENUES Operating revenues Income from investments COSTS AND EXPENSES Direct operating costs Depreciation General and administrative Interest Income from continuing operations before income (in thousands, except per share amounts) $507,331 $523,803 $531,604 7,953 28,076 10,967 515,284 551,879 542,571 345,537 361,669 330,181 82,513 41,003 ,12,289 61,447 36,563 980 49,532 28,180 1,701 481,342 460,659 409,594 on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit taxes and equity in income (loss) of affiliates 33,942 91,220 132,977 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, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2003, in conformity with accounting principles generally accepted in the United States. Tulsa, Oklahoma November 19, 2003 E R N S T & Y O U N G L L P Provision for income taxes Equity in income (loss) of affiliates net of income taxes Income from continuing operations Income from discontinued operations 14,649 40,573 54,689 (1,420) 17,873 – 3,059 53,706 9,811 2,179 80,467 63,787 NET INCOME $ 17,873 $ 63,517 $144,254 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 $ 0.36 $ 1.08 $ 1.61 – $ 0.36 $ 0.19 1.27 1.27 $ 2.88 $ 0.35 $ 1.07 $ 1.58 – 0.19 1.26 $ 0.35 $ 1.26 $ 2.84 Average common shares outstanding (in thousands) Basic Diluted 50,039 50,596 49,825 50,345 50,096 50,772 The accompanying notes are an integral part of these statements. 48 49 ASSETS CURRENT ASSETS: September 30, 2003 2002 (in thousands) September 30, 2003 2002 (in thousands, except share data) LIABILITIES AND SHAREHOLDERS’ EQUITY Consolidated Balance Sheets Cash and cash equivalents $ 38,189 $ 46,883 Accounts receivable, less reserve of $1,319 in 2003 and $1,337 in 2002 Inventories Prepaid expenses and other Total current assets 91,088 22,533 45,721 92,604 22,511 16,753 197,531 178,751 INVESTMENTS 158,770 150,175 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. 1,490,389 1,235,784 45,004 56,247 87,570 72,303 48,925 82,310 1,679,210 1,439,322 621,005 1,058,205 541,877 897,445 1,329 942 CURRENT LIABILITIES: Notes payable 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 $ 30,000 $ — 29,630 28,988 88,618 200,000 181,737 28,229 409,966 5,353 — 83,302 840,776 (10) 33,668 963,089 45,838 917,251 41,045 31,854 72,899 100,000 131,401 27,843 259,244 5,353 — 82,489 838,929 (190) 16,180 942,761 47,591 895,170 $1,415,835 $1,227,313 Accumulated other comprehensive income Less treasury stock, 3,388,588 shares in 2003 and 3,518,282 shares in 2002, at cost Total shareholders’ equity TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $1,415,835 $1,227,313 The accompanying notes are an integral part of these statements. September 30, 2002 2001 2000 50 51 Consolidated Statements of Shareholders’ Equity Consolidated Statements of Cash Flows Common Stock Shares Amount Additional Paid-in Capital Unearned Compensation Retained Earnings Treasury Stock Shares Amount (in thousands, except per share amounts) Accumulated Other Comprehensive Income (Loss) Total Balance, September 30, 2000 53,529 $5,353 $66,090 $(3,277) $813,885 3,548 $(32,412) $106,064 $955,703 Comprehensive Income: Net Income Other comprehensive loss: Unrealized losses on available- for sale securities, net Derivatives instruments lossses, net Total other comprehensive loss Total comprehensive income Cash dividends ($.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 53,529 5,353 80,324 Comprehensive Income: Net Income Other comprehensive (loss): Unrealized losses on available- for sale securities, net Derivatives instruments losses, net Minimum pension liability adjustment, net Total other comprehensive loss Total comprehensive income Distribution of Cimarex Energy Co. Stock Cash dividends ($.31 per share) Exercise of stock options Forfeiture of Restricted Stock Award Tax benefit of stock-based awards Amortization of deferred compensation 1,099 88 978 Balance, September 30, 2002 53,529 5,353 82,489 Comprehensive Income: Net Income Other comprehensive income: Unrealized gains on available- for sale securities, net Derivatives instruments amort., net Minimum pension liability adjustment, net Total other comprehensive gain Comprehensive income Cash dividends ($.32 per share) Exercise of stock options Tax benefit of stock-based awards Amortization of deferred compensation 144,254 (55,769) (986) 7,965 6,269 (15,047) (646) 774 5,808 (23,198) 1,465 (1,812) 13 943,105 3,676 (49,802) 49,309 63,517 (152,201) (15,492) (25,449) (68) (7,612) 156 1,466 (190) (181) 23 2,455 (244) 838,929 3,518 (47,591) 16,180 17,873 15,005 982 1,501 (16,026) (129) 1,753 441 372 180 144,254 (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 17,873 15,005 982 1,501 17,488 35,361 (16,026) 2,194 372 180 Balance, September 30, 2003 53,529 $5,353 $83,302 $ (10) $840,776 3,389 $ (45,838) $ 33,668 $917,251 The accompanying notes are an integral part of these statements. Years Ended September 30, 2003 2002 (in thousands) 2001 OPERATING ACTIVITIES: Income from continuing operations Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation Equity in (income) loss of affiliates before income taxes Amortization of deferred compensation Gain on sales of securities and non-monetary investment loss, net 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 $ 17,873 $ 53,706 $ 80,467 82,513 2,290 180 (5,529) (3,689) 336 1,516 251 (29,355) (11,415) (1,281) 41,225 1,589 78,631 96,504 (246,301) — 6,720 — 18,215 (221,366) 151,331 (21,331) (16,026) — 2,194 116,168 — — — — 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 (312,064) — 4,135 (5,656) 47,146 (266,439) 100,000 (50,000) (15,221) — 3,554 38,333 62,792 (55,232) (13,171) (5,611) 49,532 (3,593) 1,135 (1,189) (4,201) 876 (49,405) (68) (11,411) 29,290 18,435 15,291 2,276 46,968 127,435 (184,668) (2,279) 11,984 — 24,438 (150,525) — — (15,047) (23,198) 13,601 (24,644) 157,286 (88,813) — 68,473 Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period (8,694) 46,883 $ 38,189 (81,943) 128,826 $ 46,883 20,739 108,087 $ 128,826 The accompanying notes are an integral part of these statements. 52 53 Notes to Consolidated Financial Statements NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES September 30, 2003, 2002 and 2001 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). As described below, the Company increased the number of business segments it is reporting and how it classifies certain general and administrative expenses in 2003. These changes were driven by the new organization of the Company as a result of last year’s spin-off of the exploration and production business and to better reflect the way the Company now manages its contract drilling businesses. All prior periods reflect these changes. The number of contract drilling business segments reported have increased to three to reflect the Company’s U.S. Offshore Platform operations separately from the U.S. Land operations. Formerly, the combined U.S. segments were reported as one segment. Total operating profit for U.S. operations and the International contract drilling segment has not changed. Prior year segment disclosures have been changed to reflect the increased number of reported segments for all periods presented (see Note 15). TRANSLATION OF FOREIGN CURRENCIES The Company has determined that the functional currency for its foreign subsidiaries is the U.S. dollar. Foreign currency transaction gain (losses) were $422,000, ($5,473,000) and ($494,000), for 2003, 2002 and 2001, respectively. These amounts are included in direct operating costs. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-50 years; and other, 3-33 years). The Company charges the cost of maintenance and repairs to direct operating cost, while betterments and refurbishments are capitalized. VALUATION OF LONG-LIVED ASSETS The Company periodically evaluates the carrying value of long-lived assets to be held and used, including intangible assets, when events or circumstances warrant such a review. 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. On October 1, 2002 the Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” which did not impact the Company’s results General and administrative expenses within the Company’s contract drilling business segments have been reclassified of operations or financial position. to delineate direct operating costs from associated general and administrative costs. Formerly, both costs were included in operating costs on the consolidated statements of income. The associated general and administrative CASH AND CASH EQUIVALENTS costs of the contract drilling segments of $15,353,000, $16,172,000, and $11,553,000 for 2003, 2002 and Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which mature 2001, respectively have been reclassified to general and administrative expense on the consolidated statements within three months from the date of purchase. of income for all periods presented. General and administrative costs within the contract drilling segments continue to be included in segement operating profit. No other amounts on the consolidated statements of income were changed or affected by this reclassification. Prior year amounts for Investments and Other Assets have been reclassified to conform to current year classification. Included in the Company’s operating revenues for the fiscal year ended September 30, 2003 are reimbursements for “out-of-pocket” expenses of $31.0 million. Previously, the Company recognized reimbursements received as a reduction to the related operating costs. Emerging Issues Task Force (EITF) No. 01-14, “Income Statement Characterization of Reimbursements Received for Out of Pocket Expenses Incurred” requires that reimbursements received for “out-of-pocket” expenses be included in operating revenues. The effect of EITF 01-14 resulted in a reclassification to fiscal year 2002 and 2001, that increased operating revenues and direct operating costs by $41.0 million and $33.3 million, respectively. These reclassifications had no impact on net income. Currently, the Company is unable to convert bolivar cash balances in Venezuela into U.S. dollars or to transfer any such funds out of Venezuela as a result of exchange controls put in place by the Venezuelan government. (See Note 12 for further discussion) 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. 54 55 DRILLING REVENUES INCOME TAXES Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and Deferred income taxes are computed using the liability method and are provided on all temporary differences expenses are recognized as work progresses. For certain contracts, the Company receives lump-sum payments between the financial basis and the tax basis of the Company’s assets and liabilities. 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 OTHER POST EMPLOYMENT BENEFITS rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. 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 INVESTMENTS cost of such benefits. 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 losses in 2003 as the result of a decline in market values that were considered other than temporary by the Company. Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the 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. Company recognizing its proportionate share of the income or loss of each investee. The Company owned EMPLOYEE STOCK-BASED AWARDS approximately 21.7% of Atwood Oceanics, Inc. (Atwood) at both September 30, 2003 and 2002. The quoted Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, “Accounting market value of the Company’s investment was $71,970,000 and $87,750,000 at September 30, 2003 and for Stock Issued to Employees” and related interpretations. Fixed plan common stock options generally do 2002, respectively. Retained earnings at September 30, 2003 includes approximately $28,306,000 of not result in compensation expense, because the exercise price of the options issued by the Company equals undistributed earnings of Atwood. Summarized financial information of Atwood is as follows: September 30 Gross revenues Costs and expenses Net income (loss) Helmerich & Payne, Inc.’s equity in 2003 $ 144,766 157,568 $ (12,802) 2002 (in thousands) $ 149,157 120,872 $ 28,285 2001 $ 147,541 120,195 $ 27,346 the market price of the underlying stock on the date of grant. The plans under which the Company issues stock based awards are described more fully in Note 5. The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” September 30 Net income, as reported Add: Stock-based employee compensation expense included in the Consolidated Statements 2003 $ 17,873 2002 (in thousands) $ 63,517 2001 $144,254 net income (loss), net of income taxes $ (1,414) $ 4,206 $ 3,596 of Income, net of related tax effects 112 909 908 Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity $ 72,182 $ 71,813 447,464 40,504 215,757 263,385 372,717 24,416 143,981 276,133 $ 45,891 304,857 19,144 85,948 245,656 Helmerich & Payne, Inc.’s investment $ 56,655 $ 58,937 $ 52,153 56 Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related tax effects (4,387) (3,354) (5,951) Pro forma net income $ 13,598 $ 61,072 $139,211 Earnings per share: Basic-as reported Basic-pro forma Diluted-as reported Diluted-pro forma $ 0.36 $ 0.27 $ 0.35 $ 0.27 57 $ 1.27 $ 1.23 $ 1.26 $ 1.21 $ 2.88 $ 2.78 $ 2.84 $ 2.74 These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock NOTE 2 DISCONTINUED OPERATIONS options is amortized to expense over the vesting period, and additional options may be granted in future years. TREASURY STOCK Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in-capital using the average-cost method. CAPITALIZATION OF INTEREST The Company capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds, with the rate based on the average interest rate on related debt. Capitalized interest for 2003, 2002 and 2001 was $1.8 million, $2.5 million and $1.1 million, respectively. INTEREST RATE RISK MANAGEMENT On September 30, 2002, the Company’s distribution of 100 percent of the common stock of Cimarex Energy Co. and the merger of Key Production Company, Inc. with Cimarex was completed. In connection with the distribution, approximately 26.6 million shares of the Cimarex Energy Co. common stock on a diluted basis were 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. 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 The Company uses derivatives as part of an overall operating strategy to moderate certain financial market risks exploration and production business. Cimarex will not receive the benefit of any loss or similar tax attribute and is exposed to interest rate risk from long-term debt. To manage this risk, in October 1998, the Company arising during the time that losses from the Cimarex business are included in the Company’s consolidated federal 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 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 adjustment of interest expense. As of September 30, 2003, the Company’s interest rate swap had a notional liability for any such taxes. 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’ Summarized results of discontinued operations for the years ended September 30, 2002 and 2001, are as follows: September 30 Revenues Income from operations: Income before income taxes Tax provision 2002 2001 (in thousands) $172,827 $317,580 15,138 5,327 $ 9,811 102,125 38,338 $ 63,787 equity and reclassified into earnings in the same period or periods during which the hedged transaction Income from discontinued operations 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. 58 59 NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT NOTE 4 INCOME TAXES At September 30, 2003, the Company had $200 million in long-term debt outstanding at fixed rates and maturities as summarized in the following table. Funding of the notes occurred on August 15, 2002 and October 15, 2002 in equal amounts of $100 million. (In thousands) Issue Amount $ 25,000 $ 25,000 $ 75,000 $ 75,000 Maturity Date August 15, 2007 August 15, 2009 August 15, 2012 August 15, 2014 Interest Rate 5.51% 5.91% 6.46% 6.56% The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. The proceeds of the debt issuances were used to repay $50 million of outstanding debt, fund the Company’s rig construction program and for other general corporate purposes. At September 30, 2003, the Company had a committed unsecured line of credit totaling $125 million. Short-term loans totaling $30 million and letters of credit totaling $13.7 million were outstanding against the line, leaving $81.3 million available to borrow. The weighted average interest rate on short-term loans at September 30, 2003 was 2.0 percent. Under terms of the line of credit, the Company must maintain certain financial ratios 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. 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 percent depending on ratios described above. The line of credit matures in July, 2004. Subsequent to September 30, 2003, the Company has paid $10 million of short-term debt. At September 30, 2003, the Company held an unassociated interest rate swap tied to 30-day LIBOR in the amount of $50 million which matured 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 approximately $0.1 million on September 30, 2003. 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 is being amortized over the remaining life of the swap as interest expense. In fiscal 2003, $1.6 million was amortized and included in interest expense. Changes to the value of the interest rate swap subsequent to the date the $50 million debt was paid are recorded to income. CURRENT: Federal Foreign State DEFERRED: Federal Foreign State The components of the provision (benefit) for income taxes from continuing operations are as follows: Years Ended September 30, 2003 2002 (In thousands) 2001 $ (34,495) $ 13,324 $ 28,911 6,870 883 (26,742) 42,835 (3,383) 1,939 41,391 5,080 1,022 19,426 16,019 3,732 1,396 21,147 8,870 2,651 40,432 8,850 4,701 706 14,257 $ 54,689 2001 $106,163 26,814 $132,977 TOTAL PROVISION: $ 14,649 $ 40,573 The amounts of domestic and foreign income from continuing operations are as follows: 2003 Years Ended September 30, Income from continuing operations before income taxes and equity in income (loss) of affiliates: Domestic Foreign $ 31,164 2,778 $ 33,942 2002 (In thousands) $ 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, 2003 2002 2001 U.S. Federal income tax rate Effect of foreign taxes State income taxes Effective income tax rate 35% 4 4 43% 35% 7 2 44% 35% 4 2 41% The components of the Company’s net deferred tax liabilities are as follows: September 30, 2003 2002 2000 (In thousands) Deferred tax liabilities: Property, plant and equipment Available-for-sale securities Equity investments Total deferred tax liabilities Deferred tax assets: Financial accruals Pension reserve Other Total deferred tax assets Net deferred tax liabilities $ 153,736 25,106 17,349 196,191 6,079 4,917 3,458 14,454 $ 181,737 $111,822 18,170 18,216 148,208 7,196 2,802 6,809 16,807 $131,401 60 61 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. During fiscal 2001 the Company purchased 773,800 shares at a cost of approximately $23,198,000 under previous Outstanding at October 1, authorizations from the board of directors. The Company did not purchase any shares in fiscal 2003 or 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. Restricted stock 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. Granted Exercised Adjustment for Cimarex spinoff Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2003 2002 2001 Weighted-Average Exercise Price Options Weighted-Average Exercise Price Options Weighted-Average Exercise Price $20.28 3,136 $25.78 2,955 $22.94 27.74 16.93 — 23.85 $21.41 19.34 820 (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 Options 3,875 611 (130) — (29) 4,327 2,575 1,597 The following summary reflects the stock option activity for the Company’s common stock and related information for 2003, 2002, and 2001. (shares in thousands): In March 2001, the Company adopted the 2000 Stock Incentive Plan (the “Stock Incentive Plan”). The Stock The following table summarizes information about stock options at September 30, 2003 (shares in thousands): 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 2003 and 2002, 610,700 and 819,800 options, respectively, were granted under the 2000 plan. There were no restricted stock grants in fiscal 2003 or 2002. There was no activity under this plan during fiscal 2001. On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. to the 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 380 1,376 2,571 4,327 Weighted-Average Remaining Life Weighted-Average Exercise Price 1.9 5.2 7.5 6.3 $10.58 $17.03 $25.35 $21.41 Options 380 1,195 1,000 2,575 Weighted-Average Exercise Price $10.58 $16.76 $25.74 $19.34 Company’s shareholders. The distribution was recorded as a dividend and resulted in a decrease to consolidated The weighted-average fair values of options at their grant date during 2003, 2002, and 2001 was $10.72, $12.47, shareholders equity of approximately $152.2 million. Any options held by Cimarex employees at the distribution and $13.01, respectively. The estimated fair value of each option granted is calculated using the Black-Scholes date were automatically forfeited per the terms of the Company’s stock incentive plans. Both vested and unvested option-pricing model. The following summarizes the weighted-average assumptions used in the model: 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 common stock as the result of the spin-off of Cimarex. The adjustment was made in such a way that the aggregate intrinsic value of the options and the ratio of the exercise price per share to the market value per share remained the same. Expected years until exercise Expected stock volatility Dividend yield Risk-free interest rate 2003 2002 2001 4.5 45% .75% 3.1% 4.5 48% .8% 4.0% 4.5 43% .8% 5.2% On September 30, 2003, the Company had 50,140,364 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 percent or more of 62 63 the outstanding common stock or ten business days following the commencement of a tender offer or exchange NOTE 7 FINANCIAL INSTRUMENTS offer that would result in a person owning 15 percent 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 had $200 million of long-term debt outstanding at September 30, 2003, which had an estimated the Company is the surviving corporation), or more than 50 percent 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 fair value of $226.5 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 long-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 $0.1 million at September 30, 2003, 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 A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: method of accounting (see Note 1): Basic weighted-average shares Effect of dilutive shares: Stock options Restricted stock 2003 50,039 555 2 557 2002 (in thousands) 49,825 508 12 520 Diluted weighted-average shares 50,596 50,345 2001 50,096 644 32 676 50,772 At September 30, 2003, options to purchase 1,030,791 shares of common stock at a weighted-average price of $27.86 were outstanding, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. 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. Equity Securities: September 30, 2003 September 30, 2002 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $ 33,300 $ 46,325 $ 64,276 $ 43,846 $ 0 $ 3,772 $ 97,576 $ 86,399 During the years ended September 30, 2003, 2002, and 2001, marketable equity available-for-sale securities with a fair value at the date of sale of $18,215,000, $46,692,000, and $24,438,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $8,582,000, $25,893,000, and $3,314,000, respectively, and the gross realized losses totaled $3,053,000, $232,000, and $0, respectively. 64 65 NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) NOTE 9 EMPLOYEE BENEFIT PLANS The table below presents changes in the components of accumulated other comprehensive income (loss). In July 2003, the Company revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan”) to Unrealized Appreciation (Depreciation) on Securities Interest Rate Swap Minimum Pension Liability Total (in thousands) close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals will be discontinued and the plan frozen. These revisions to the Pension Plan had no effect upon pension expense accruals for fiscal 2003. Balance at September 30, 2000 $106,064 $ — $ — $106,064 The following tables set forth the Company’s disclosures required by SFAS No. 132, “Employers’ Disclosures 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 (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 2003 Change: Pre-income tax amount Income tax provision Amortization of swap (15,388) (25,449) 24,846 29,731 (11,298) (net of $602 income tax benefit) — Realized gains in net income (net of $2,101 income tax) (3,428) 15,005 (1,590) 604 — (986) (986) (127) 48 11 — (68) (1,054) — — 982 — 982 — — — — — (12,277) 4,665 — — (7,612) (7,612) 2,421 (920) — — 1,501 (90,352) 34,334 (737) (56,755) 49,309 (28,632) 10,880 11 (15,388) (33,129) 16,180 32,152 (12,218) 982 (3,428) 17,488 Balance at September 30, 2003 $ 39,851 $ (72) $ (6,111) $ 33,668 About Pensions and Other Postretirement Benefits.” Change in benefit obligation: Years Ended September 30, 2003 2002 (in thousands) Benefit obligation at beginning of year $ 68,134 $ 51,733 Service cost Interest cost Curtailments Actuarial loss Benefits paid 5,401 4,423 (8,444) 6,269 (4,609) 4,769 3,835 (1,232) 11,036 (2,007) Benefit obligation at end of year $ 71,174 $ 68,134 Change in plan assets: Years Ended September 30, 2003 (in thousands) Fair value of plan assets at beginning of year Actual gain (loss) on plan assets Benefits paid Fair value of plan assets at end of year Funded status of the plan Unrecognized net actuarial loss Unrecognized prior service cost Accumulated other comprehensive loss (before tax) Accrued benefit cost $ 48,286 9,958 (4,609) $ 53,635 $ (17,539) 15,052 20 (9,856) $ (12,323) 2002 $ 53,987 (3,694) (2,007) $ 48,286 $ (19,848) 24,929 284 (12,277) $ (6,912) Weighted-average assumptions: Discount rate Years Ended September 30, 2003 6.25% Expected return on plan assets Rate of compensation increase 8.00% 5.00% 2002 6.75% 8.00% 5.00% 2001 7.50% 9.00% 5.00% 66 67 COMPONENTS OF NET PERIODIC PENSION EXPENSE: Years Ended September 30, 2003 Service cost Interest cost Expected return on plan assets Amortization of prior service cost Amortization of transition asset Curtailment gain Recognized net actuarial loss Net pension expense DEFINED CONTRIBUTION PLAN $ 5,401 4,423 (3,807) 180 — 1,550 84 2002 (in thousands) $ 4,769 3,835 (4,804) 238 (540) 120 — 2001 $ 3,851 3,330 (5,415) 238 (540) 17 — $ 7,831 $ 3,618 $ 1,481 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 $5,568,000, $5,226,000, and $4,499,000 in 2003, 2002, and 2001, respectively. NOTE 10 OTHER CURRENT ASSETS AND ACCRUED LIABILITIES Prepaid expenses and other consist of the following: Time deposits Income tax receivable Deferred mobilization Other September 30, 2003 2002 (in thousands) $ 322 32,619 2,993 9,787 $ 45,721 $ 337 9,304 — 7,112 $ 16,753 Accrued liabilities consist of the following: Taxes payable – operations Workers compensation claims Payroll and employee benefits Deferred income Other September 30, 2003 2002 (in thousands) $ 8,386 $ 7,660 2,820 6,768 1,535 9,479 2,506 7,032 6,016 8,640 $ 28,988 $ 31,854 NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2003 2002 (in thousands) 2001 Cash payments: Interest paid, net of amount capitalized Income taxes paid $ 11,375 $ 5,838 $ 477 $ 9,779 $ 1,546 $ 42,523 68 69 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 and are typically not secured by collateral. The Company provides an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on managements knowledge of customer accounts. No significant credit losses have been experienced by the Company. SELF-INSURANCE regulations the Company on October 1, 2003, submitted a request to the Venezuelan government seeking permission to convert existing bolivar balances into U.S. dollars. The Company is unable to predict if or when this request will be approved. As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. From August of 2002 to August of 2003, there was a 13 percent devaluation of the bolivar. As a result, the Company experienced a $624,000 devaluation loss. This 13 percent devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal 2003 and if a 25 to 50 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $3,200,000 to $5,100,000. The Company self-insures a significant portion of its expected losses under its worker’s compensation, general, In late August 2003, the Venezuelan state petroleum company agreed, on a go-forward basis, to pay a portion and automobile liability programs in the United States. Insurance coverage has been purchased for individual of the Company’s dollar-based invoices in U.S. dollars. While this is a positive development in light of the existing claims that exceed $2 million. The Company records estimates for incurred outstanding liabilities for unresolved exchange controls, there is no guarantee as to how long this arrangement will continue. Were this agreement worker’s compensation, general liability claims and for claims that are incurred but not reported. Estimates are to end, The Company would revert back to receiving these payments in Bolivars and thus increase Bolivar cash based on historic experience and statistical methods that the Company believes are reliable. Nonetheless, balances and exposure to devaluation. insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claims development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. 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. Recent events in Venezuela have created greater governmental instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in material and supplies necessary to operate some or all of its Venezuelan drilling rigs. 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 The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable addresses financial accounting and reporting for obligations associated with the retirement of tangible long- balances and bolivar cash balances. In Venezuela, while approximately 60 percent of the Company’s billings lived assets and the associated asset retirement costs. The Statement requires that the fair value of a liability to the Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar, for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate PDVSA typically pays all amounts owed in bolivars. The Company, historically, has usually been able to convert of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carry- the bolivars received in payment of the dollar-based billings into U.S. dollars in a timely manner. In January ing amount of the long-lived asset. The Statement is effective for financial statements issued for fiscal years 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 beginning after June 15, 2002. There was no impact on the Company’s results of operations and financial bolivars to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the position upon adopting SFAS No. 143 on October 1, 2002. bolivar into U.S. dollars. As a result of these exchange controls, the Company has been unable since January 2003 to convert its bolivar cash balances into U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was approximately 14 billion bolivars or approximately $8.8 million. Historically, the Company has kept bolivar cash balances at necessary minimum levels to fund local operating costs. In compliance with applicable 70 71 NOTE 14 CONTINGENT LIABILITIES AND COMMITMENTS COMMITMENTS The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2003, the Company has commitments of approximately $35 million for the purchase of drilling equipment. LEASES depreciation; and allocated general and administrative costs; but excludes corporate costs for other depreciation and other income and expense. General and administrative costs are allocated to the segments based primarily on specific identification, and to the extent that such identification was not practical, on other methods which the Company believes to be a reasonable refelction of the utilization of services provided. 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 each of the years ended In May 2003, the Company signed a six-year lease for approximately 114,000 square feet of office space near September 30, 2003, 2002, and 2001 is shown in the following table: downtown Tulsa. The lease will be effective as the Company moves during the first quarter of fiscal 2004. Future annual minimum lease payments under this noncancelable lease and other noncancelable leases as of September 30, 2003 were as follows: (in thousands) Fiscal Year 2004 2005 2006 2007 2008 Thereafter Total Amount $ 1,285 1,048 1,311 1,385 1,385 1,732 $ 8,146 Total rent expense was $1,108,000, $1,027,000 and $736,000 for 2003, 2002 and 2001, respectively. NOTE 15 SEGMENT INFORMATION The Company operates principally in the contract drilling industry. The Company’s contract drilling business includes the following operating segments: U.S. Land, U.S. Offshore Platform, and International. The contract drilling operations consist primarily of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company’s primary international areas of operation include Venezuela, Colombia, Ecuador, Argentina and Bolivia. 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. Other includes Investments and corporate operations. As described in Note 2 the Company’s oil and gas operations were distributed to Company shareholders on September 30, 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; direct operating costs; 72 External Sales Inter- Segment Total Sales Operating Profit Depreciation Total Assets (in thousands) 2003: Contract Drilling U.S. Land U.S. Offshore Platform International Services Real Estate Other Eliminations Total 2002: Contract Drilling $ 273,993 112,633 109,812 496,438 10,893 7,953 — $ 515,284 $ 231,637 U.S. Land U.S. Offshore Platform 132,249 151,392 International Services 515,278 8,525 28,076 — $ 551,879 Real Estate Other Eliminations Total 2001: Contract Drilling $ 221,857 U.S. Land U.S. Offshore Platform 128,459 170,270 International Services 520,586 11,018 10,967 — Real Estate Other Eliminations Total $ — — — — 1,439 — (1,439) $ — $ 809 — — 809 1,491 — (2,300) $ — $ 4,487 — — 4,487 1,545 — (6,032) $ 542,571 $ — $ 273,993 112,633 109,812 496,438 12,332 7,953 (1,439) $ 515,284 $ 18,565 36,306 5,149 60,020 6,569 — — $ 66,589 $ 44,726 12,799 20,092 77,617 2,535 2,361 — $ 728,707 170,580 243,918 1,143,205 31,472 241,158 — $ 82,513 $1,415,835 $ 232,446 132,249 151,392 516,087 10,016 28,076 (2,300) $ 551,879 $ 30,493 38,688 13,128 82,309 5,064 — — $ 87,373 $ 26,311 10,809 20,336 57,456 1,844 2,147 — $ 555,137 173,474 254,940 983,551 26,562 217,200 — $ 61,447 $1,227,313 Additions to Long-Lived Assets $ 216,590 7,191 12,733 236,514 7,628 2,159 — $ 246,301 $ 236,254 48,273 23,157 307,684 3,181 1,199 — $ 312,064 $ 67,580 40,111 28,475 136,166 6,315 — — $142,481 $ 16,701 9,576 18,838 45,115 2,284 2,133 — $ 366,193 139,980 268,947 775,120 22,621 367,123 — $ 136,740 7,323 38,022 182,085 1,190 1,393 — $ 49,532 $1,164,864 $ 184,668 $ 226,344 128,459 170,270 525,073 12,563 10,967 (6,032) $ 542,571 73 The following table reconciles segment operating profit per the table on page 72 to income before taxes and NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) equity in income (loss) of affiliates as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, 2003 2002 2001 Segment operating profit Unallocated amounts: Income from investments Corporate and administrative expense Interest expense Corporate depreciation Other corporate expense Total unallocated amounts Income before income taxes and equity in income (loss) of affiliates $ 66,589 $ 87,373 $ 142,481 7,953 (25,650) (12,289) (2,361) (300) (32,647) 28,076 (20,391) (980) (2,147) (711) 3,847 10,967 (16,627) (1,701) (2,133) (10) (9,504) $ 33,942 $ 91,220 $ 132,977 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, 2003 2002 2001 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $ 405,472 31,763 50,783 6,081 21,185 $ 515,284 $ 867,365 75,179 46,778 12,984 55,899 $1,058,205 $ 400,487 50,763 47,501 11,612 41,516 $ 551,879 $ 698,316 72,630 49,353 14,339 62,807 $ 897,445 $ 372,301 49,163 37,839 28,886 54,382 $ 542,571 $ 448,119 84,856 33,520 16,195 67,361 $ 650,051 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, 16.3 percent, and 23.9 percent of the total consolidated revenues during the years ended September 30, 2003, 2002, and 2001, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 14.6 percent, 14.7 percent, and 12.8 percent of total consolidated revenues in the years ended September 30, 2003, 2002, and 2001, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 11.5 percent, 12.3 percent, and 8.4 percent of total consolidated revenues in the years ended September 30, 2003, 2002, and 2001, respectively. Collectively, the receivables from these customers were approximately $36.0 million and $35.0 million at September 30, 2003 and 2002, respectively. 2003 Revenues Gross profit Net income Basic net income per common share: Diluted net income per common share: 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 (in thousands, except per share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $ 113,313 $ 126,320 $ 137,025 $ 138,626 14,021 607 .01 .01 19,024 2,574 .05 .05 26,788 8,162 .16 .16 27,401 6,530 .13 .13 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $ 143,883 $ 132,344 $ 152,049 $ 123,603 37,378 18,127 15,604 24,093 8,129 10,872 47,477 22,551 28,218 19,815 4,899 8,823 .36 .31 .36 .31 .16 .22 .16 .22 .46 .57 .45 .56 .10 .18 .10 .17 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 fourth quarter of 2003 includes after-tax gains on sale of available-for-sale securities of $3.2 million, $0.06 per share, on a diluted basis. Net income in the fourth quarter of 2003 includes an after-tax equity loss in loss of affiliates of $2 million, $0.04 per share, on a diluted basis. 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. 74 75 Directors Officers 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 Gordon K. Helm Controller 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 John D. Zeglis**(***) Chairman and Chief Executive Officer AT&T Wireless Services Basking Ridge, New Jersey * Member, Audit Committee ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee 76 Stockholders’ Meeting The annual meeting of stockholders will be held on March 3, 2004. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 27, 2004. Stock Exchange Listing Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol “HP.” The newspaper abbre- viation most commonly used for financial reporting is “HelmP.” Options on the Company’s stock are also traded on the New York Stock Exchange. Stock Transfer Agent and Registrar As of December 15, 2003, there were 1,017 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. Also located on the investor relations section of the Company’s Web site are certain corporate governance documents, including the following: the charters of the committees of the Board of Directors; the Company’s Corporate Governance Guidelines; the Code of Ethics for Principal Executive Officer and Senior Financial Officers; certain Audit Committee Practices and a description of the means by which employees and other interested persons may communicate certain concerns to the Company’s Board of Directors, including the communication of such concerns confiden- tially and anonymously via the Company’s ethics hotline at 1-800-205-4913. Quarterly reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request. Direct Inquiries To: Investor Relations Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 Telephone: (918) 742-5531 Internet Address: http://www.hpinc.com