Helmerich & Payne
Annual Report 2004

Plain-text annual report

04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 2 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 $241 million as of September 30, 2004. F I N A N C I A L H I G H L I G H T S Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets Years Ended September 30, 2004 2003 ( in thousands , except per share amounts) $ 620,928 $ 515,284 4,359 .09 .323 88,972 1,406,844 17,873 .35 .32 246,301 1,417,770 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 3 To the Co-owners of Helmerich & Payne, Inc.: When I worked on my first Annual Report twenty-three years ago, that publication was the single most important way we communicated to shareholders. A popular staple back then was my dad’s President’s Letter. He started a tradition of penning a wide-ranging commentary back in the1960s, and after he retired, I picked up a similar approach with my first letter in 1990. Over the years, I tackled a range of issues that bear on all U.S. public companies, including common education, double taxation, executive compensation, and energy policy. I always enjoyed readers’ feedback and particularly remember meeting the author of the most famous President’s Letter, Warren Buffet, who recommended to me that I turn the task back to my predecessor. That’s an offer our Chairman continues to turn down each year, although it still gets a laugh between us. Over these same years, the role of the Annual Report has changed significantly. Its importance as a communication tool has given way to more timely webcasts and conference calls, strict disclosures and legal requirements, and the broad use of increasingly popular and accessible websites. Along with a growing number of public companies, we have combined our Annual Report with our 10-K filing as a cost-effective approach to compliance. This letter will change as this document continues to evolve. Before summarizing our operations for 2004, I want to thank our employees for delivering outstanding field performance during a challenging year. 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 4 Contract Drilling Operations Crude oil prices surged during the last half of 2004, erasing previous records and reaching past $50 per barrel. Additionally, natural gas prices remained resilient in 2004, even in the face of record storage inventories heading into the 2004-2005 heating season. In short, our customers have not experienced a healthier commodity price environment in decades. According to statistics compiled by Baker Hughes, average rig activity improved world-wide by approximately 13 percent in 2004, with nearly three quarters of the gain coming in the U.S. land market. Almost half of the world’s active rigs are in the U.S. land market, which at year-end had 1,129 active rigs, compared with 967 at the end of 2003. In sharp contrast, the U.S. offshore market continued to soften and ultimately translated into a significant negative impact on this year's financial results. U.S. Offshore Operations After 20 years of steady performance, the Company has suffered in recent years through an industry-wide downturn in activity levels for conventional water depths, where the majority of the Company’s offshore platform rigs operate. While this segment appears to have stabilized, the Company took a $51.5 million non-cash asset impair- ment charge against the carrying value of its Gulf of Mexico platform rigs, reflecting our continued expectation that any recovery in this sector will be slow. The Company retired one offshore platform rig at 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 5 the end of 2004, leaving 11 rigs in the fleet, which we believe are the newest and best available in their class in the Gulf of Mexico market. At year-end, three rigs were working on full day rates, two rigs were on standby rates, and six rigs were available for work. International Operations Significant improvements in Venezuela and Argentina, as well as operations in Hungary and Equatorial Guinea, helped bolster performance in 2004. On average, the Company had five more rigs working in 2004 than in 2003, resulting in a 39 percent increase in revenue days. Including a $1.7 million insurance settlement, revenues increased 37 percent and operating profit climbed to $14 million compared with $5.1 million in 2003. Activity in Venezuela increased by over three rigs in 2004, and at the close of the year, nine rigs were running, with a tenth likely to commence in January 2005. After Venezuela, Ecuador is the second strongest market for the Company in South America. At year-end, the Company had seven rigs operating there, and an eighth has a letter of intent to begin operations in December 2004. Colombia had very weak activity in 2004, but at the close of the year, one rig had returned to work, and the Company received a letter of intent to return a second rig to work in December 2004. International operations in South America strengthened measurably in 2004, and with the return of four older rigs to the U.S. and new contracts in Venezuela, Ecuador, and Colombia, the Company anticipates that it will have 23 rigs out of 27 rigs working by the end of the first quarter of fiscal 2005. 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 6 The Company's first international FlexRig*, working in Hungary, should work through the first fiscal quarter of 2005. The Company completed a multi-well contract in Chad using its second international FlexRig during the year, and that rig has since returned to the U.S. fleet and is working in central Florida. The Company continues to actively prospect in other regions of the world for attractive growth opportunities, principally in areas where FlexRig technology can be applied to add considerable value. U.S. Land Operations In July, the U.S. land rig count surpassed the previous high mark set in 2001, and activity continues to grow. The Company added ten net rig years to its fleet capacity during 2004 and worked 13 more rig years than in 2003. Revenues and cash flow increased 27 and 48 percent, respectively, and operating profit doubled that of 2003. At the close of the year, the Company had 87 rigs available to the market, 80 of which were working. FlexRig utilization during 2004 was 99 percent, compared with 73 percent for the Company’s remaining fleet. The Company completed its FlexRig3 construction project, delivering the 32nd FlexRig3 at the end of March. FlexRig3s have drilled almost 500 wells, 73 percent of which were drilled under or on the customers’ planned drilling time. In further recognition of the superior value, half of the FlexRig3 fleet is being used to drill directional, more technically * The term “FlexRig” used throughout this Annual Report is a Company trademark Registered in the U.S. Patent and Trademark Office. 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 7 difficult wells compared to an average of 26 percent for the industry fleet. The FlexRig3 is setting the industry pace in pricing with 20 out of 32 FlexRig3s currently contracted at $14,000 per day or higher. The counter cyclical investment made in the FlexRig has strategically positioned the Company by doubling its U.S. capacity and by demonstrating a clear performance differential to the customer. Forty-nine of our 50 FlexRigs are located in the U.S. and will give the Company improved potential earnings leverage in this growing up-cycle. Outlook The Company had its share of frustration and disappointment in 2004, but we are encouraged by the momentum we see developing for 2005 and beyond. U.S. land market activity indicates that the industry is entering a different, but improving part of the drilling cycle, and as rig counts continue to move up, we expect dayrate pricing will also ratchet up. The Company’s FlexRig3 continues to receive high marks in the field, and as oil field costs escalate, the Company expects to see increasing recognition of its value in the form of higher margins. We are also encouraged by improvements in the international market and look to this arena to be a leading source of long-term growth. Although the offshore platform market has been a disappointment, the Company maintains a solid foothold in this segment of the business with the newest rigs in the Gulf of Mexico fleet and a wealth of engineering and project management experience that is essential for 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 8 developing future opportunities. While we have no immediate plans or announcements regarding new rigs, we do have customers expressing interest in projects in the U.S., as well as internationally. We expect that additional investments will be accompanied by term contracts and dayrates that provide improved financial returns and that better reflect what we strongly believe to be unparalleled drilling efficiencies and service. Sincerely, Hans Helmerich President December 9, 2004 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 9 Financial & Operating Review SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Years Ended September 30, 2004 2003 2002 Operating Revenues Operating Costs Depreciation① Operating Income Income from Investments Interest Expense General and Administrative Expense Income from Continuing Operations Net Income Diluted Earnings Per Common Share: Income from Continuing Operations Net Income *$000’s omitted, except per share data. ①2004 includes an asset impairment charge of $51,516 †All data excludes discontinued operations except net income. SUMMARY FINANCIAL DATA* Cash** Working Capital** Investments Property, Plant, 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 593,326 416,631 145,941 30,754 27,602 12,695 37,661 4,359 4,359 .09 .09 507,331 345,537 82,513 79,281 7,953 12,289 41,003 17,873 17,873 .35 .35 523,803 361,669 61,447 100,687 28,076 980 36,563 53,706 63,517 1.07 1.26 65,296 185,983 161,532 998,674 1,406,844 200,000 914,110 88,972 38,189 110,848 158,770 1,058,205 1,417,770 200,000 917,251 246,301 46,883 105,852 150,175 897,445 1,227,313 100,000 895,170 312,064 48 39 11 32 130 99 73 87 48 54 43 40 12 32 127 97 67 81 51 39 26 40 12 33 111 96 78 84 83 51 04-HP-876_firstsection.qxd 12/15/04 2:41 PM Page 10 2001 2000 1999 1998 1997 1996 1995 1994 531,604 330,181 49,532 151,891 10,967 1,701 28,180 80,467 144,254 384,762 248,568 77,317 58,877 32,063 2,730 23,306 36,470 82,300 1.58 2.84 .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 2.00 128,826 223,980 203,271 650,051 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 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 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 1 Helmerich & Payne, Inc. FORM 10-K, 2004 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 2 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, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 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.) 1437 S. BOULDER AVE., SUITE 1400, TULSA, OKLAHOMA 74119 (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. [ ] 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, 2004, the aggregate market value of the voting stock held by non-affiliates was $1,378,913,985. Number of shares of common stock outstanding at December 3, 2004: 50,610,987. 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, 2004 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 2, 2005 10-K Parts Parts I and II Part III 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 3 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 6, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 44 THROUGH 53 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. 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 4 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 almost all of the Company’s operating revenues. The Company is also engaged in the ownership, development, and operation of commercial real estate. The Company is organized into two separate operating entities, contract drilling and real estate. Both businesses operate independently of the other through wholly owned subsidiaries. Operating decentralization is balanced by a cen- tralized 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: U.S. land drilling, U.S. offshore platform drilling and international drilling. The Company's U.S. land drilling is conducted primarily in Oklahoma, Texas, Wyoming, Colorado, and Louisiana, and offshore from platforms in the Gulf of Mexico and California. The Company also operated in eight international locations during fiscal 2004: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Equatorial Guinea, Chad, and Hungary. In addition, the Company is providing drilling consulting services for one cus- tomer in Russia. 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 busi- ness. The Company does not own any common stock of Cimarex Energy Co. During fiscal 2004, the Company incorporated in Vermont a wholly-owned captive insurance subsidiary. The Company believes that the use of this captive will reduce its insurance costs. 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 2004, the Company received approximately 56 percent of its consolidated revenues from the Company’s ten largest contract drilling customers. BP plc, ExxonMobil Corporation, and Shell Oil Company (respectively, "BP", “ExxonMobil” and “Shell”), including their affiliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for BP, ExxonMobil, and Shell on a world-wide basis. Revenues from drilling services performed for BP, ExxonMobil and Shell in fiscal 2004 accounted for approximately 10.8 percent, 10.7 percent and 8.4 percent, respectively, of the Company’s consolidated revenues 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 1 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 5 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 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 land drilling 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”, were the next generation of FlexRigs which incorporated new drilling technology and new environmental and safety design. This new design included 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 FlexRig3s were completed by June of 2003. Subsequently, the Company constructed seven more FlexRig3s at an approximate cost of $11,250,000 each. Construction of these rigs was completed by March of 2004. All FlexRigs are available for work in the Company’s U.S. 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. During fiscal 2004, all drilling services were performed on a “daywork” contract 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 2004. 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 ter- mination payment” to be paid to the contractor if a contract is terminated prior to the expiration of the fixed term. While the duration for current fixed-term contracts are for six month to three 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. 2 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 6 U . S . L A N D D R I L L I N G At the end of September, 2004 and 2003, the Company had 87 and 83, respectively, of its land rigs available for work in the United States. The total number of rigs owned at the end of the period increased by a net of four rigs, resulting from five additional FlexRigs being completed during the year and removing from service one older conventional rig. The Company’s U.S. land operations contributed approximately 56 percent of the Company’s consolidated revenues during fiscal 2004, compared with 53 percent of consolidated revenues during fiscal 2003 and 42 percent of consolidated revenues during fiscal 2002. Rig utilization in fiscal 2004 was 87 percent, up from 81 percent in fiscal 2003. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 97 percent during fiscal 2004 while the Company’s conventional rigs had an average utilization rate of approximately 67 percent. At the close of fiscal 2004, 80 land rigs were working out of 87 available rigs. In November of 2004, the Company sold two conventional 2,000 horsepower U.S. land rigs for a total of $23.9 million. U . S . 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 14 percent of the Company’s consolidated revenues during fiscal 2004, compared with 22 percent of consolidated revenues during fiscal 2003 and 24 percent of consolidated revenues during fiscal 2002. Rig utilization in fiscal 2004 was 48 percent, down from 51 percent in fiscal 2003. At the end of this fiscal year, the Company had six of its 11 offshore platform rigs under contract and it continued to work under management contracts for three customer-owned rigs. Revenues from drilling services performed for the Company’s largest offshore platform drilling customer totaled approximately 61 percent of U.S. offshore platform revenues during fiscal 2004. It is likely during the first six months of calendar 2005 that one additional platform rig will be stacked and one management contract will be terminated. As a result of declining financial trends and unfavorable market conditions in the Gulf of Mexico, the Company completed an analysis of its offshore platform business in the Gulf of Mexico. Based on this analysis, the Company recorded a pre- tax asset impairment charge of $51.5 million in the fourth quarter of 2004. 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 24 percent of the Company’s consolidated revenues during fiscal 2004, compared with 21 percent of consolidated revenues during fiscal 2003 and 27 percent of consolidated revenues during fiscal 2002. Rig utilization in fiscal 2004 was 54 percent, up from 39 percent in fiscal 2003. Venezuela Venezuelan operations continue to be a significant part of the Company’s operations. During fiscal 2004, the Company moved two additional deep drilling rigs into the country, bringing the Company rig count to 13 land drilling rigs in Venezuela at the end of fiscal 2004. However, in early fiscal 2005, the Company moved a highly mobile rig to the United States, leaving the rig count at twelve. The Company worked primarily for the Venezuelan state petroleum company, PDVSA, during fiscal 2004, and revenues from this work accounted for approximately eight percent of the Company’s consolidated revenues during the fiscal year and 33 percent of international drilling revenues. Revenues 3 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 7 generated from all Venezuelan drilling operations contributed approximately 37 percent of the Company’s consolidated revenues during 2004, compared with 29 percent of consolidated revenues during fiscal 2003 and 34 percent of consolidated revenues during 2002. The Company had nine rigs working in Venezuela at the end of fiscal 2004. The Company’s rig utilization rate in Venezuela has increased from approximately 33 percent during fiscal 2003 to approximately 65 percent in fiscal 2004. Even though the Company is, at this time, unable to predict future fluctuations in its utilization rates during fiscal 2005, the Company believes that the prospects are good for returning at least one of its idle rigs back to work in Venezuela during fiscal 2005. Ecuador At the end of fiscal 2004, the Company owned eight rigs in Ecuador. The Company’s utilization rate was approximately 74 percent during fiscal 2004, down from approximately 85 percent in fiscal 2003. Revenues generated by Ecuadorian drilling operations contributed approximately seven percent of the Company’s consolidated revenues during fiscal 2004, as compared with 10 percent of consolidated revenues during fiscal 2003 and nine percent of consolidated revenues during fiscal 2002. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 15 percent of international drilling revenues during fiscal 2004. The Ecuadorian drilling contracts are primarily with large international oil companies. Colombia During fiscal 2004, the Company moved one rig from Colombia to Venezuela, leaving two rigs in Colombia. The Company's utilization rate in Colombia was approximately 13 percent during fiscal 2004, down from approximately 21 percent in fiscal 2003. The revenues generated by Colombian drilling operations contributed approximately one percent of the Company's consolidated revenues in fiscal 2004, as compared with one percent of consolidated revenues during fiscal 2003 and two percent of consolidated revenues during fiscal 2002. At the end of fiscal 2004, the Company was operating one rig in Colombia, with a commitment for the second rig to begin work in early fiscal 2005. Other Locations In addition to its operations in Venezuela, Ecuador and Colombia, in fiscal 2004, the Company owned six rigs in Bolivia, one rig in Argentina, one rig in Hungary and one rig in Chad. At the end of fiscal 2004, two rigs were working in Bolivia, one in Argentina and one in Hungary. As of the end of November, 2004, one rig was working in Bolivia. At the end of fiscal 2004 one rig was moved from Chad to the United States. During November of 2004, three rigs were moved from Bolivia to the United States. During fiscal 2004, 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 commenced a drilling consulting services contract in Russia. 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. Utica Square contains approximately 441,588 usable square feet, composed of retail space of 379,018 usable square feet, office space of 38,785 usable square feet, storage space of 6,600 usable square feet and common area space of 17,185 usable square feet. The Company’s real estate operations occupy approximately 4,140 square feet of general office and storage space within the shopping center. Occupancy in the shopping center increased from 85 percent in fiscal 2003 to 91 percent in fiscal 2004 with the additions of an upscale salon and day spa, and a clothing store for teens and young adults. 4 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 8 At the end of the 2004 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. Six of the Company’s units are currently leased. 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 82 percent, which is down from 98 percent in fiscal 2003. Reduced occupancy is the result of the relocation of one tenant’s research facility to a university. The Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses. In August of 2004, the Company sold approximately 1.73 acres of undeveloped land in Southpark. The sales price totaled approximately $1 million. Southpark is located in a high growth area of southeast Tulsa and is suitable for mixed commercial and light industrial. Subsequent to such sale and at the end of fiscal 2004, the Company owned approximately 218 acres in Southpark consisting of approximately 205 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 decreased to 82 percent in 2004 from 93% in fiscal 2003 due to the loss of one tenant and a reduction of space by another. 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. The Company has contracted with a professional engineering and planning firm to prepare a comprehensive master plan to aid in the possible future development of Southpark. The Company owns a five-building complex called Tandem Business Park. The property 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/ware- house space. Occupancy has decreased from 84 percent to 69 percent during fiscal 2004 due to the departure of five small tenants. The Company also owns a 12-building complex, consisting of approximately 204,600 square feet of office/ware- house space, called Tulsa Business Park. The property is located south and east of the Space Center facility, separated by a city street, and contains approximately 12 acres. During fiscal 2004, occupancy has decreased from 86 percent to 81 per- cent. 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 is located on approximately 2.5 acres. During fiscal 2004, occupancy has remained at 94%. The second, called Maxim Place, consists of one office/warehouse building containing approximately 33,750 square feet and is located on approximately 2.25 acres. During fiscal 2004, occupancy has increased from 17 percent to 44 percent with the addition of two tenants. In addition, the Company has established an offsite disaster recovery center at this facility which occupies approximately 3,517 square feet. The Company, during fiscal 2004, completed relocation within Tulsa of its executive offices. The razing of its former headquarters building will be completed in the first quarter of fiscal 2005. No development plans for the site are pending. F I N A N C I A L Information relating to revenues, total assets and operating profit or loss by business segments may be found on pages 79 through 81 of the Company’s Annual Report. E M P L O Y E E S The Company had 3,056 employees within the United States (six of which were part-time employees) and 1,195 employees in international operations as of September 30, 2004. 5 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 9 A V A I L A B L E I N F O R M A T I O N Information relating to the Company’s internet address and the Company’s SEC filings may be found on page 83 of the Company’s Annual Report. R I S K F A C T O R S In addition to the risk 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 attempt to differentiate its services based upon its engineering design expertise, operational efficiency, and 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 basis other than price. Also, future improvements in operational efficiency and safety by the Company’s competitors could negatively affect the Company’s ability to differentiate its services. 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. Also, current economic conditions have encouraged prospective tenants to construct owner-occupied buildings rather than lease third party space. 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 has insurance coverage for comprehensive general liability, public liability, property damage, workers compensation, and employer's liability. Generally, deductibles are $2 million per occurrence on claims that fall under these coverages, except that property damage deductibles on rig properties are generally $1 million per occurrence. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance 6 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 10 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 2005. No assurance can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2005 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 U.S. 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 2004, approximately 24 percent of the Company’s consolidated revenues were generated from the international contract drilling business. Approximately 78 percent of the international revenues were from operations in South America and approximately 85 percent 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. 7 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 11 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 was paid in pesos with the balance of such accounts receivable paid in U.S. dollars. The Company did not experience Argentine currency losses in fiscal 2004. 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 and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the Central Bank. 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 in October of 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which would convert 14 billion bolivars into U.S. dollars. In January 2004, the Venezuelan government approved the Company’s request to convert bolivar cash balances to U.S. dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by this amount. 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. As a result of the 20 percent devaluation of the bolivar during fiscal 2004, the Company experienced total devaluation losses of $1.9 million during that same period. These devaluation losses may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. There have been recent press reports of a potential devaluation in calendar 2005. However, the amount and exact timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2005 activity levels are similar to fiscal 2004 and if a ten percent to twenty percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.2 million to $2.3 million. 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 again receive 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. 8. Government Regulation and Environmental Risks 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, the United States and various other countries have environmental 8 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 12 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 drilling operations. 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 million 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 at September 30, 2004, 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, 2004 was approximately $216.4 million. At September 30, 2004, the Company had in place a committed unsecured line of credit totaling $50 million with no outstanding borrowings. The Company, as of September 30, 2004, had letters of credit totaling $13 million outstanding against such line of credit. The Company’s line of credit interest rate is based on LIBOR plus 87 to 112.5 basis points or prime minus 1.75 to 1.50 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 borrow- ings. Although market interest rates were at historical lows during fiscal year 2004, interest rates could rise for various rea- sons 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, 2004, the Company owned stocks in other publicly held companies with a total market value of $240.7 million. 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 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 sec- tion of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial strength. In October 2004, the Company sold 1,000,000 shares of its position in Atwood Oceanics, Inc. as part of a 2,175,000 share public offering by Atwood. The sale generated approximately $16.5 million ($0.32 per diluted share) of net income for the first quarter of fiscal 2005. The Company owns 2,000,000 shares of Atwood after the sale. 11. Reliance on Small Number of Customers In fiscal 2004, the Company received approximately 56 percent of its consolidated revenues from the Company’s ten largest contract drilling customers and approximately 30 percent 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. 12. Key Personnel 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. 9 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 13 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 improvements in 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. 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 U.S. drilling rigs as of September 30, 2004: 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 Oklahoma Texas Texas Louisiana Oklahoma 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 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 10 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) 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 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 14 Location Texas Texas Oklahoma Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Colorado Texas Wyoming HIGHLY MOBILE RIGS Oklahoma Texas Wyoming Oklahoma Texas Oklahoma Texas Texas Wyoming Texas Wyoming CONVENTIONAL RIGS Texas Oklahoma Texas Oklahoma Texas Texas Louisiana Oklahoma Texas Oklahoma Texas Rig 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240 241 158 156 159 141 142 143 145 155 146 147 154 110 96 118 119 120 162 79 80 89 92 94 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 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 11 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) SCR Mechanical Mechanical Mechanical Mechanical Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 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 1,500 900 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 2,000 1,500 1,500 1,500 1,500 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 15 Location Oklahoma Texas Oklahoma Texas Texas Texas Texas Texas Texas Texas Texas Texas Louisiana Texas Louisiana Louisiana Texas Rig 98 122 97 99 137 149 191 192 72 73 125 134 136 157 161 163 139 OFFSHORE PLATFORM RIGS Louisiana Louisiana Gulf of Mexico Louisiana Gulf of Mexico Louisiana Louisiana Louisiana Gulf of Mexico Gulf of Mexico Gulf of Mexico 91 203 205 206 100 105 106 107 201 202 204 Optimum Depth Rig Type Drawworks: Horsepower 20,000 16,000 20,000 26,000 26,000 26,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000+ 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 SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Conventional Self-Erecting Tension-leg Self-Erecting Conventional Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 1,500 1,700 2,000 2,000 2,000 2,000 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 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 U.S. land drilling rigs for the periods indicated: Years ended September 30, Number of rigs owned at end of period Average rig utilization rate during period* 2000 38 85% 2001 49 97% 2002 66 84% 2003 83 81% 2004 87 87% *A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. 12 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 16 The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2004: Location Argentina Bolivia* Bolivia* Bolivia* Bolivia Bolivia Bolivia Chad Colombia Colombia Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Hungary Venezuela* Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 177 171 172 173 123 151 175 167 133 152 22 23 132 176 121 117 138 190 168 140 148 160 113 115 116 127 128 129 135 150 174 153 Optimum Depth Rig Type Draw-Works: Horsepower 30,000 16,000 16,000 20,000 26,000 30,000+ 30,000 18,000 30,000 30,000+ 18,000 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 30,000 30,000+ SCR Mechanical Mechanical Mechanical SCR SCR SCR SCR (FlexRig1) SCR SCR SCR (Heli Rig) SCR (Heli Rig) SCR SCR SCR SCR SCR SCR SCR (FlexRig1) Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 3,000 1,000 1,000 2,000 2,100 3,000 3,000 1,500 3,000 3,000 1,700 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 3,000 3,000 *Rig was returned to the United States during November of 2004. 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*† 2000 40 47% 2001 37 56% 2002 33 51% 2003 32 39% 2004 32 54% * 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. 13 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 17 R E A L E S T A T E O P E R A T I O N S See Item 1. BUSINESS, pages 4 through 5 of this Report. S T O C K P O R T F O L I O Information required by this item regarding the stock portfolio held by the Company may be found on page 46 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 management, the amount of ultimate liability with respect to these actions will not materially affect the financial position, results of operations, or liquidity of the Company. The Company is not a party to, and none of its property is subject to, any material pending legal proceedings. I T E M 4 . S U B M I S S I O N O F M AT T E R S T O A V O T E O F S E C U R I T Y H O L D E R S None. 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 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. Douglas E. Fears, 55 Vice President and Chief Financial Officer since 1988 Steven R. Mackey, 53 Vice President, Secretary and General Counsel Secretary since 1990; Vice President and General Counsel since 1988 W. H. Helmerich, III, 81 Chairman of the Board Director since 1949; Chairman of the Board since 1960 Hans Helmerich, 46 President and Chief Executive Officer Director since 1987; President and Chief Executive Officer since 1989 George S. Dotson, 63 Vice President Director since 1990; Vice President since 1977 and President and Chief Operating Officer of Helmerich & Payne International Drilling Co. since 1977 14 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 18 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 under the symbol “HP”. 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 2003 High Low $ 30.23 $ 23.45 28.94 32.80 30.30 22.60 24.72 25.70 2004 High Low $ 28.37 $ 23.77 30.61 29.55 29.07 27.02 24.25 24.01 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 2003 $0.080 0.080 0.080 0.080 2004 $0.080 0.080 0.080 0.0825 2003 2004 $4,000,982 $4,011,879 4,002,239 4,002,971 4,009,076 4,017,204 4,032,709 4,160,221 The Company paid a cash dividend of $0.0825 per share on December 1, 2004, to shareholders of record on November 15, 2004. Payment of future dividends will depend on earnings and other factors. As of December 3, 2004, there were 860 record holders of the Company’s common stock as listed by the transfer agent’s records. 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 equity compensation plans of the Company as of September 30, 2004. Plan Category: Equity compensation plans 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) approved by security holders (1) 4,456,665 $ 22.028 1,157,805 Equity compensation plans not approved by security holders (2) Total – 4,456,665 – $ 22.028 – 1,157,805 (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. 15 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 19 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 Condition contained at pages 25 through 53 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 which is not included in the five-year summary of selected financial data. 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 2000 2001 2002 2003 2004 (in thousands except per share amounts) Sales, operating, and other revenues $416,272 $542,571 $551,879 $515,284 $620,928 Asset Impairment Charge — — — — Income from continuing operations 36,470 80,467 53,706 17,873 51,516 4,359 Income from continuing operations per common share: Basic Diluted Total assets Long-term debt 0.74 0.73 1.61 1.58 1.08 1.07 0.36 0.35 0.09 0.09 1,200,854 1,300,121 1,227,313 1,417,770 1,406,844 50,000 50,000 100,000 200,000 200,000 Cash dividends declared per common share 0.285 0.30 0.31 0.32 0.3225 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 25 through 53 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 49- 51 51- 52 52- 53 53 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 55 through 82 of the Company’s Annual Report. 16 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 20 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 pro- cedures. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer believe that: • the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and • the Company’s disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to the Company’s management, and made known to the Company’s Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure. b) Changes in internal controls. There have been no changes in the Company’s internal controls over financial reporting during the Company’s last fiscal quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. I T E M 9 B . O T H E R I N F O R M A T I O N None. PART III I T E M 1 0 . D I R E C T O R S A N D E X E C U T I V E O F F I C E R S O F T H E C O M P A N Y Information required under this item with respect to Directors and with respect to delinquent filers pursuant to Item 405 of Regulation S-K is incorporated by reference from the Company's definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004. The information required by this Item with respect to the Company’s Executive Officers appears on page 14 of this 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 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004. 17 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 21 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 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004. 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 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004. 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 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004. 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, 2004, 2003 and 2002 54 55 Consolidated Balance Sheets at September 30, 2004 and 2003 56-57 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2004, 2003 and 2002 Consolidated Statements of Cash Flows for the Years Ended September 30, 2004, 2003 and 2002 Notes to Consolidated Financial Statements 58 59 60-82 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. 18 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 22 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, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. *10.2 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. *10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is incorporated herein by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. *10.4 Form of Nonqualified Stock Option Agreement for the 1990 Stock Option Plan is incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 33-55239 on Form S-8, dated August 26, 1994. *10.5 Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein by reference to Exhibit 10.9 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 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. *10.12 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. 10.13 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. 19 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 23 10.14 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. 10.15 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. 10.16 Office Lease dated May 30, 2003, between K/B Fund IV and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2003, SEC File No. 001-04221. *10.17 Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 9, 2004. 10.18 Shareholders Agreement and Registration Rights Agreement dated July 19, 2004 between Helmerich & Payne International Drilling Co. and Atwood Oceanics, Inc. is incorporated herein by reference to Exhibit 1.1 of the Company’s Amended Schedule 13D filed on July 21, 2004. 10.19 Underwriting Agreement dated October 13, 2004, between Helmerich & Payne International Drilling Co. and various underwriters is incorporated herein by reference to Exhibit 1.1 of the Company’s Form 8-K filed on October 14, 2004. *10.20 Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 6, 2004. 13. The Company’s Annual Report to Shareholders for fiscal 2004. 21. List of Subsidiaries of the Company is incorporated herein by reference to Exhibit 21 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2003, SEC File No. 001-04221. 23.1 Consent of Independent Registered Public Accounting Firm. 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. * Management or Compensatory Plan or Arrangement. (b) Reports on Form 8-K The Company filed two reports on Form 8-K during the last quarter of fiscal 2004 as follows: (cid:1) Form 8-K dated July 22, 2004, 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 2004 earnings. (cid:1) Form 8-K dated September 2, 2004, disclosing the approval by the Company’s Board of Directors of the Helmerich & Payne, Inc. Director Deferred Compensation Plan, to become effective October 1, 2004. 20 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 24 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 13, 2004 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 13, 2004 /s/ George S. Dotson By George S. Dotson, Director Date: December 13, 2004 /s/ W.H. Helmerich, III By W. H. Helmerich, III, Director Date: December 13, 2004 /s/ Edward B. Rust, Jr. By Edward B. Rust, Jr., Director Date: December 13, 2004 /s/ John D. Zeglis By John D. Zeglis, Director Date: December 13, 2004 /s/ Glenn A. Cox By Glenn A. Cox, Director Date: December 13, 2004 /s/ Hans Helmerich By Hans Helmerich, Director and CEO Date: December 13, 2004 /s/ L. F. Rooney, III By L. F. Rooney, III, Director Date: December 13, 2004 /s/ Paula Marshall-Chapman By Paula Marshall-Chapman, Director Date: December 13, 2004 /s/ Douglas E. Fears /s/ Douglas E. Fears By Douglas E. Fears, (Principal Financial Officer) Date: December 13, 2004 /s/ Gordon K. Helm By Gordon K. Helm, Controller (Principal Accounting Officer) Date: December 13, 2004 21 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 25 C E R T I F I C A T I O N I, Hans Helmerich, certify that: 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the 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 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 13, 2004 22 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 26 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 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 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, 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/ Douglas E. Fears Douglas E. Fears, Chief Financial Officer December 13, 2004 23 04-HP-876_10K.qxd 12/15/04 2:43 PM Page 27 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, 2004 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 13, 2004 /s/ Douglas E. Fears Douglas E. Fears Chief Financial Officer December 13, 2004 24 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 24 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 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 6 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. 25 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 25 S P I N - O F F A N D M E R G E R T R A N S A C T I O N S On September 30, 2002, Helmerich & Payne, Inc. completed its distribution of 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders and the 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 has reported the results of its former exploration and production division (Cimarex Energy Co.) as discontinued operations. E X E C U T I V E S U M M A R Y Helmerich & Payne, Inc. is a contract drilling company which owned and operated a total of 130 drilling rigs at September 30, 2004. The Company’s primary markets are the United States land rig business in which the Company owned 87 rigs, the United States offshore platform rig business in which the Company owned 11 offshore platform rigs, and the international land rig business in which the Company owned 32 rigs at year end. Over the past year, crude oil and natural gas prices have risen significantly as the supply and demand outlook for both commodities have changed. Crude oil demand has improved as markets 26 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 26 like China and India, as well as the U.S., have recorded increases in demand for crude oil due to economic growth. The U.S. natural gas market has been promising for some time, but only recently have natural gas production levels and overall reserve totals for natural gas declined to a point that there is a perceived shortage of deliverable natural gas to meet the prospective total demand in the U.S. Because of these dynamics, the overall demand for drilling rig services has increased both in the U.S. and internationally. Additionally, most offshore rig markets have also responded positively, with the exception of the offshore platform rig market. Fundamental changes in the makeup of the offshore platform rig business have negatively affected offshore platform rig utilization dramatically over the past two years. As a result, while the Company’s business in its U.S. land and international sectors improved during 2004, the offshore platform rig business declined and suffered an operating loss for the year due to a material asset impairment charge in that segment. As the Company looks to 2005, it appears that markets in both U.S. land and international segments are in a good position to record improved financial results. The U.S. offshore platform business does not appear to have good probabilities for improvement, although it should be fairly stable given the type of projects currently in place. Overall however, Helmerich & Payne, Inc. should benefit from the prospective improvements brought about by historical highs in commodity prices, and the excellent financial condition of the Company. 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 27 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 27 2004 was $4.4 million ($0.09 per share), compared with $17.9 million ($0.35 per share) for 2003 and $63.5 million ($1.26 per share) for 2002. Included in net income was a pre-tax asset impairment charge (discussed in detail later) of $51.5 million ($31.9 million after-tax or $0.63 per share) in 2004 and income from discontinued operations of $9.8 million ($0.19 per share) in 2002. Included in the Company’s net income, but not related to its operations, were after-tax gains from the sale of investment securities of $14.1 million($0.28 per share) in 2004, $3.3 million ($0.07 per share) in 2003, and $15.2 million($0.30 per share) in 2002. In addition to income from security sales, the Company recorded net income during 2004 of $1.5 million ($0.03 per share) from non-monetary investment gains. 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 net income of $0.01 per share in 2004, a loss of $0.03 per share in 2003, and net income of $0.06 per share in 2002. (See Liquidity section of MD&A for discussion of the sale of a portion of the Company’s Atwood Oceanic stock shortly after September 30, 2004). Consolidated revenues were $620.9 million in 2004, $515.3 million in 2003, and $551.9 million in 2002. U.S. land revenues rose steadily from 2002 to 2004, while U.S. offshore platform rig revenues declined significantly during the same period. 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 86 rigs in 2004, 76 in 2003, and 57 in 2002. U.S. land rig utilizations for the Company were 87 percent in 2004, 81 percent in 2003, and 84 percent in 2002. Revenue reductions in the 28 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 28 offshore platform business were mainly due to a drop in rig utilization to 48 percent in 2004, from 51 percent in 2003 and 83 percent in 2002. Late in 2003, renegotiations for additional work for two rigs under the expiring contracts resulted in lower dayrates, thereby contributing to the decline in revenues. Also late in 2003, two other rigs were moved to an active standby status which also lowered revenues, even though those rigs remained active. International rig revenues declined from 2002 to 2003, and rose during 2004 as rig utilizations fell from 51 percent in 2002, to 39 percent in 2003, and then rose to 54 percent in 2004. Revenues from investments were $27.6 million in 2004, $8.0 million in 2003, and $28.1 million in 2002. 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 $25.4 million in 2004, $5.5 million in 2003, and $24.8 million in 2002. 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 $2.0 million in 2004, $2.5 million in 2003, and $3.6 million in 2002. Direct operating costs in 2004 were $416.6 million or 70 percent of operating revenues, compared with $345.5 million or 68 percent of operating revenues in 2003, and $361.7 million or 69 percent of operating revenues in 2002. The 2003 expense to revenue percentage would basically be the same as 2002 and only slightly less than 2004 except for the fact that in the offshore platform segment in 2003 one contract had higher than normal margins and significant early termination revenues. 29 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 29 Depreciation expense was $94.4 million in 2004, $82.5 million in 2003, and $61.4 million in 2002. Depreciation expense increased significantly over the three-year period as the Company placed into service 13 new rigs in 2002, 19 new rigs in 2003, and 5 new rigs in 2004. The Company anticipates 2005 depreciation expense to be consistent with 2004, unless capital expenditures rise unexpectedly. Additional depreciation as a result of the 5 new land rigs put in service during 2004 and capital expenditures will be offset by the reduction in offshore platform rig depreciation as a result of the asset impairment charge discussed below. During the fourth quarter of 2004, the Company recognized a pre- tax, non-cash asset impairment charge of $51.5 million related to its Gulf of Mexico offshore platform rigs. During fiscal 2004, average revenue per day for the Company’s offshore platform rigs steadily declined from an average of $32,790 per day during the first quarter to $28,380 during the fourth quarter. Average cash margins per rig day declined throughout the year from $15,206 during the first quarter of 2004 to $11,003 during the fourth quarter. Total operating profit for the offshore platform rig segment had averaged over $9 million per quarter for both fiscal years 2002 and 2003, with an $8.9 million operating profit recorded for the fourth quarter of 2003. During fiscal 2004, operating profit was $4.4 million, $4.1 million, $3.8 million, and $4.3 million (excluding the asset impairment charge) for the four sequential fiscal quarters as shown below. Quarters Ended 12/31/2003 3/31/2004 6/30/2004 9/30/2004 (in thousands) Operating profit, as reported $ 4,375 $ 4,106 $ 3,826 Asset impairment charge Operating profit, excluding – – – $ (47,180) 51,516 asset impairment charge $ 4,375 $ 4,106 $ 3,826 $ 4,336 30 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 30 During this same three year period, industry platform rig utilization in the Company’s market declined from 72% during the first quarter of fiscal 2002, to 47% during the fourth quarter of fiscal 2004. During this same period, utilization for the Company’s platform rigs fell from 100% (10 of 10) during the first quarter 2002, to a low of 42% (five of 12) during the first and second quarters of 2004. Although activity rose slightly during the third and fourth quarters of 2004, it is expected to drop back to five active rigs during the first quarter of 2005. As demonstrated by these financial trends, the Company’s offshore platform business has continued to decline. During the first half of 2004, the Company believed that two new contracts obtained for work that commenced during the third and fourth quarters and the increases in commodity prices were precursors to more bidding activity in the market. That anticipated increase in bid activity did not materialize and bidding opportunities were very low during the third and fourth quarters. Additionally, oil and natural gas commodity prices reached new historical highs during the Company’s fourth fiscal quarter, but there was no improvement in the market for the Company’s offshore platform rigs and no indication from customers that new opportunities would be forthcoming in the foreseeable future. As a result of these events and circumstances, management performed an analysis of the general industry market conditions in the offshore platform rig business, and the prospective market demand for the offshore platform rigs owned by the Company. Based upon this analysis, management determined that the carrying value of certain of the offshore rigs exceeded the estimated undiscounted future cash flows associated with these assets. Accordingly, an asset impairment charge 31 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 31 was recorded to reduce the carrying value of the assets to their estimated fair value. Because quoted market prices are not available for offshore platform rigs, the fair value was determined based upon estimated discounted future cash flows and rig utilization. The cash flows were estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make the rig marketable, suitability of rig size and makeup to existing platforms, and new competitive dynamics due to lower industry utilization. The timing of the impairment was predicated on a number of industry and rig-specific factors that, in the opinion of management, appear to be longer term in nature than originally expected. Future cash flow limitations for existing rigs became more apparent as long term arrangements for a few of the Company’s newer rigs were adjusted during the year. Also, one of the Company’s more marketable rigs was stacked during the fourth quarter, with no prospects for work in the foreseeable future. It was determined that one of the Company’s older rigs was no longer marketable and, therefore, was written down to its salvage value and removed from the active rig count as of September 30, 2004. The Company also assessed its international land rig fleet because of relatively low rig utilizations during fiscal years 2002, 2003 and 2004. During that three year period, the Company averaged having 32 rigs available with average annual international fleet utilizations of 51% in 2002, 39% in 2003, and 54% in 2004. Because of strong land rig demand in the U.S., five international rigs were returned to the U.S. during the first quarter of fiscal 2005. Activity in the international market also improved and the Company’s active rig count in South 32 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 32 America increased during the first quarter. During October 2004, the Company had 27 international land rigs available for service, with 23 rigs (85%) that were either active or had been committed with signed letters of intent. Market conditions for international work have improved substantially over the past six months. Based upon management’s analysis, the undiscounted estimated future cash flows exceeded the carrying value of our international land rigs. General and administrative expenses totaled $37.7 million for 2004, $41 million for 2003, and $36.6 million for 2002. The decrease in total general and administrative expenses from 2003 to 2004 was primarily from a reduction in pension expense due to a decrease in the benefit accrual, reduced field training expense as the FlexRig training program was completed, and lower salary and bonus expense. These reductions were partially offset by increases in property, casualty and health insurance expenses. The increase from 2002 to 2003 was primarily the result of increases in employee benefits relating to pension, medical insurance, and 401(k) matching expenses. Employee salaries and bonuses also contributed to the increase, as well as increases in property and casualty insurance costs. Interest expense was $12.7 million in 2004 and $12.3 million in 2003, compared with $1.0 million in 2002. The Company issued $200 million 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 beginning of fiscal year 2003. Additionally, the Company drew on its bank line of credit during 2003, with $30 million drawn at the end of 2003. The $30 million was paid early in fiscal 2004, with no bank loan outstanding at the end of 2004. 33 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 33 The provision for income taxes totaled $4.4 million in 2004, $14.6 million in 2003, and $40.6 million in 2002. Effective income tax rates on income from continuing operations were 55 percent in 2004, 43 percent in 2003, and 44 percent in 2002. Effective income tax rates are higher for the Company’s international operations than for its U.S. operations. As a result, the aggregate effective rate is higher in years when international operations make up a higher percentage of financial operating profit. International operating profit, as a percent of total Company operating profit, was 68 percent in 2004, eight per- cent in 2003, and 15 percent in 2002. (See Note 5 of the Financial Statements). 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 4 A N D 2 0 0 3 U.S. LAND 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 2004 2003 % Change (in thousands, except operating statistics) $347,793 246,177 7,765 56,528 $ 37,323 27,472 $ 11,700 $ 8,001 $ 3,699 87 87% $273,993 201,398 9,304 44,726 $ 18,565 22,588 $ 11,436 $ 8,221 $ 3,215 83 81% 26.9% 22.2 (16.5) 26.4 101.0 21.6% 2.3 (2.7) 15.1 4.8 7.4 Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. 34 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 34 The Company’s U.S. land rig operating profit increased 101.0 percent from 2003 to 2004. This increase was due to improved rig utilization experienced by the Company, the increased number of rigs available during 2004, and the improvement in average rig margins per rig day during the year. The improved margins were a result of slightly increased average dayrates and lower expenses per rig day experienced during 2004. The lower expense per day in 2004 was due to the elimination of excess crew overages that occurred in 2003 in connection with placing 19 new rigs into service. During the fourth quarter of 2004, the Company began to experience a more significant improvement in rev- enue and margin per day due to higher levels of U.S. land rig activity. Although it is difficult to predict the extent of continued improvement, it is anticipated that rig activity will continue to improve as long as crude oil and natural gas prices remain at the historically high levels experienced during the second half of 2004. Total number of rigs owned at the end of 2004 as compared to 2003 increased by a net of four rigs, resulting from five additional FlexRigs being completed during the year and removing from service one older conventional rig. As a result of the new rigs put in service, and a full year of depreciation of rigs put in service during 2003, total U.S. land rig depreciation increased 26.4 percent from 2003 to 2004. It is anticipated that depreciation will increase during 2005, but at a much lower rate than in 2004. 35 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 35 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 4 A N D 2 0 0 3 U.S. OFFSHORE OPERATIONS Revenues Direct operating expenses General and administrative expense Depreciation Asset impairment charge Operating profit (loss)* 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 2004 2003 (in thousands, except operating statistics) % Change $ 84,993 $112,633 52,987 3,256 12,107 51,516 60,589 2,939 12,799 – $ (34,873) $ 36,306 2,088 $ 29,432 $ 16,509 $ 12,923 11 48% 2,233 $ 38,239 $ 17,822 $ 20,417 12 51% (24.5)% (12.5) 10.8 (5.4) – (196.1) (6.5)% (23.0) (7.4) (36.7) ( 8.3) (5.9) 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. Operating profit in the Company’s U.S. offshore platform rig operations fell from $36.3 million during 2003 to a loss of $34.9 million in 2004 due primarily to the asset impairment charge of $51.5 million. Excluding the asset impairment charge, operating profit would have been $16.6 million for 2004, which is a $19.7 million decline from 2003. Operating profit (loss), as reported Asset impairment charge Operating profit, excluding asset impairment charge 2004 $ (34.9) 51.5 $ 16.6 (in millions) 2003 $ 36.3 — $ 36.3 *Note: This table is a reconciliation of operating profit (loss) for the offshore platform segment for fiscal 2004 and 2003, which is provided to assist with yearly comparisons. 36 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 36 Financial performance during 2004 was hindered by continued softness in the offshore platform rig market which kept rig utilizations at an average of 48 percent for 2004. More importantly, total revenues and revenue per day declined due to changes in the nature of contract terms on several of the Company’s rigs. During 2003, contracts for two of the Company’s newest rigs terminated and were renegotiated at lower dayrates just prior to the end of the year. Additionally, two other rigs that were working at full dayrates during 2003 were changed to standby status, thereby reducing total revenues and profitability. These specific transactions, coupled with an overall softening in the market, caused average rig revenue and margin per rig day to decline during 2004. 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 4 A N D 2 0 0 3 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 2004 2003 % Change (in thousands, except operating statistics) $150,698 113,988 2,144 20,530 $ 14,036 6,266 $ 19,884 $ 14,278 $ 5,606 32 54% $109,812 81,461 3,110 20,092 $ 5,149 4,515 $ 19,603 $ 14,140 $ 5,463 32 39% 37.2% 39.9 (31.1) 2.2 172.6 38.8% 1.4 1.0 2.6 – 38.5 Operating statistics of per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of management contracts and currency revaluation expense. Included in international operations revenue and margin per day calculations for fiscal 2004 is an insurance gain of $1.7 million. Without the insurance gain, the revenue per day and margin per day would have been $19,616 and $5,338, respectively. 37 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 37 Operating profit for the Company’s international operations increased 172.6 percent from 2003 to 2004 due to higher rig activity, improved margin per rig day, and lower general and administrative expense resulting from reduced salary, bonus and travel expense. Rig activity improved, primarily due to improved demand in the Company’s largest international operation in Venezuela. Venezuelan operations improved substantially as the government-owned oil company, PDVSA, increased their spending in an attempt to improve overall production rates following the reduction in production caused by a workers’ strike and attempted coup in Venezuela during 2003. Despite overall improvement of conditions in Venezuela, the currency there was devalued during the year, resulting in a loss of $1.9 million for 2004. (See MD&A Section on Foreign Currency Exchange Rate Risk for more discussion.) Additionally, Company operations improved substantially in Bolivia and Hungary. Although operations in Chad ceased at the end of 2004, and it is anticipated that Hungary’s operations will cease during the first half of 2005, the Company expects that operations will improve in the Company’s operations located in Venezuela, Colombia and Ecuador during 2005. Late in 2004 and during the first quarter of 2005, the Company returned to the United States five of its 32 international land rigs. Two of the five rigs have contracts for work as of the first quarter of 2005. Three of the five rigs were scheduled to arrive during the first quarter 2005 in the U.S. for an assessment of their viability in the U.S. market. As a result of the improved demand for contract drilling work in South America, and the reduction in available Company rigs, it is anticipated that rig utilizations will improve during 2005. 38 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 38 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 4 A N D 2 0 0 3 REAL ESTATE Revenues Direct operating expenses Depreciation Operating profit 2004 $ 9,842 3,347 2,253 $ 4,242 2003 (in thousands) $ 10,893 1,789 2,535 $ 6,569 % Change (9.6)% 87.1 (11.1) (35.4) Operating profit in the Company’s Real Estate division fell 35.4 percent from 2003 to 2004, but performance of its core operations actually improved. The reduction in operating profit was due primarily to a decline in the profits recorded for the sale of raw land in 2004 versus 2003. While the sale of raw land has not been an ongoing component of income in the Real Estate division, the Company recorded gains on sales of land totaling $1.0 million and $2.7 million in 2004 and 2003, respectively. Direct operating expenses increased as compared to 2003 due to demolition costs in 2004 of over $.8 million relating to the razing of the Company’s former headquarters building, and an increase in advertising expense. 39 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 39 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) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. The Company’s operating profit in its U.S. land rig operations fell by 39.1 percent from 2002 to 2003, despite the fact that commodity prices were very strong during 2003. 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 2003. 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 particularly 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 40 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 40 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. During 2003, 19 FlexRig3s were completed and put into service. Two first generation FlexRigs 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. 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. OFFSHORE 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 (in thousands, except operating statistics) % Change $ 112,633 $132,249 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 – (38.6) Operating statistics of per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts. During 2003, the Company experienced a reduction in activity days and rig utilization in its U.S. offshore platform rig operations. Total revenues and revenue per day during 2003 were aided by the recognition of revenue due to early termination of contracts and higher dayrates for three rigs. 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. Capital expenditures were reduced dramatically due to the fact that there were no new platform rigs under 41 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 41 construction during 2003, whereas two new platform rigs were completed 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 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 of per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses, the effects of management contracts, or the effect of currency revaluation expense. 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 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. The Company has currency risks in Venezuela described in detail later in the MD&A under Foreign Currency Exchange Rate Risk. Due to that exposure, the Company recorded currency devaluation losses for Venezuelan operations totaling $.6 million in 2003 and $4.4 million in 2002. 42 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 42 During 2002, the Company recorded an estimated devaluation loss totaling $1.2 million 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 devaluation loss by approximately $1.0 million by securing agreements with its customers that limited the portion of the accounts receivable that was paid in pesos with the balance of such accounts receivable paid in U.S. dollars. 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 Years Ended September 30, REAL ESTATE Revenues Direct operating expenses Depreciation Operating profit 2003 $ 9,842 3,347 2,253 $ 4,242 2002 (in thousands) $10,893 1,789 2,535 $ 6,569 % Change (9.6)% 87.1 (11.1) (35.4) Operating profit increased by 29.7 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 South Park investment. Pre-tax profit from the sale of land was approximately $2.7 million. Depreciation expense increased in 2003 due to the acceleration of depreciation on the Company’s headquarters building, which was demolished in 2004. Overall combined occupancy and resulting revenues generated from all the other real estate properties did not materially fluctuate from 2002 to 2003. 43 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 43 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 $89 million in 2004, $246.3 million in 2003, and $312.1 million in 2002. Net cash provided from operating activities for those same time periods was $135.4 million in 2004, $96.5 million in 2003, and $151.8 million in 2002. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $30.9 million in 2004, $18.2 million in 2003, and $47.1 million in 2002. The Company’s 2005 capital spending estimate is $55 million, down from $89 million in 2004 due to the completion of the FlexRig construction in March, 2004. During 2000, the Company announced its 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 $11.0 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 were completed by March, 2004. In August 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities from 5 to 12 years and a weighted average interest rate of 6.31 percent. 44 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 44 Funding of the notes occurred on August 15, 2002 and October 15, 2002 in equal amounts of $100 million. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. Proceeds from the intermediate-term debt were used to repay the balance of the Company’s outstanding debt of $50 million in September 2002, to help fund the Company’s rig construction program and for other general corporate purposes. On September 30, 2004, the Company had a committed unsecured line of credit totaling $50 million, with no money drawn and letters of credit totaling $13 million outstanding against the line. The line of credit matures in 2005 and bears interest of LIBOR plus .875 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 a minimum level of tangible net worth. Current ratios for September 30, 2004, and 2003 were 4.1 and 2.3, respectively. The debt to total capitalization ratio was 18 percent and 20 percent at September 30, 2004 and 2003, respectively. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2004, had a market value of $240.7 million. The Company’s investments in Atwood Oceanics, Inc., and Schlumberger, Ltd., made up almost 94 percent of the portfolio’s market value on September 30, 2004. 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. In July 2004, Atwood Oceanics, Inc., (Atwood) the Company’s equity affiliate, filed a Registration Statement covering all 3,000,000 shares of Atwood stock owned by H&P. 45 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 45 On October 19, 2004, Atwood and Helmerich & Payne closed a public offering in which Helmerich & Payne sold 1,000,000 Atwood shares and received approximately $45.8 million. The Company now owns 2,000,000 shares or approximately 13.3 percent of the outstanding shares of Atwood. During 2004, the Company paid a dividend of $.3225 per share, or a total of $16.2 million, representing the 32nd 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, 2004 Number of Shares Cost Basis Market Value Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total M AT E R I A L C O M M I T M E N T S 3,000,000 1,230,000 ( in thousands, except share amounts) $ 57,824 19,539 8,272 $ 85,635 $ 142,620 82,791 15,298 $240,709 The Company has no off balance sheet arrangements. The Company’s contractual obligations as of September 30, 2004, are summarized in the table below: Payments Due By Year Total 2005 2006 2007 2008 2009 After 2009 Long-term debt (a) $ 200,000 $ – $ – $ 25,000 $ – $ 25,000 $150,000 Operating leases (b) 9,929 2,542 2,261 1,844 1,412 1,408 462 Total Contractual Obligations $209,929 $2,542 $ 2,261 $ 26,844 $1,412 $ 26,408 $150,462 ( in thousands) (a) See Note 4 “Long-term Debt” to the Company’s Consolidated Financial Statements. (b) See Note 14 “Commitments and Contingencies” to the Company’s Consolidated Financial Statements. The above table does not include obligations for the Company’s pension plan, for which the recorded liability at September 30, 2004 is $19.2 million. Based on current information available from plan actuaries, the Company anticipates no contributions will be made in 2005. Future contributions beyond 2005 are difficult to estimate due to multiple variables involved. 46 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 46 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, which relate 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 as incurred. 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’s management assesses the potential impairment of its long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that trigger such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilizations, declining revenue per rig day, declining cash mar- gin per rig day, completion of specific contracts, and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more 47 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 47 than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. See additional discussion of impairment assumptions, including determination of fair value, under Results of Operations. Use of different assumptions could result in an impairment charge different from that reported. The Company is self-insured or maintains high deductibles for certain losses relating to worker’s compensation, general, product, and auto liabilities. Generally, deductibles are $2 million per occurrence on claims that fall under these coverages. Insurance is also purchased on rig properties and generally deductibles are $1 million per occurrence. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all cir- cumstances. 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. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. The Company’s pension benefit costs and obligations are dependent on various actuarial assumptions. The Company makes assumptions relating to discount rates, rate of compensation increase, and expected return on plan assets. The Company bases its discount rate 48 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 48 assumption on current yields on AA-rated corporate long-term bonds. The rate of compensation increase assumption reflects actual experience and future outlook. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect expense recognized and obligations recorded in future periods. 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 con- tracts 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. 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 and in several South American countries, as well as a labor contract for work in Equatorial Guinea and Russia. With the exception of Venezuela, the Company’s exposure to currency valuation losses is usually minimal due to the fact that virtually all invoice 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. 49 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 49 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, resulting in the Company recording an estimated loss of $1.2 million in 2002. The Company was able to reduce this estimated loss by approximately $1.0 million during 2003 by securing agreements with its customers that limited the portion of the accounts receivable that was paid in pesos with the balance of such accounts receivable paid in U.S. dollars. At the present time, the Company has one rig working in Argentina. 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 to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 40% 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 compliance with applicable 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. In January 2004, the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars and the remittance of $8.8 million U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by this amount. 50 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 50 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. As a result of the 20% devaluation of the bolivar during fiscal 2004 (from September 2003 through August 2004), the Company experienced total devaluation losses of $1.9 million during that same period. This 20% devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. There have been recent press reports of a potential devaluation in calendar 2005. However, the exact amount and timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2005 activity levels are similar to fiscal 2004 and if a 10% to 20% devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.2 million to $2.3 million. 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 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 prices are determined by a number of factors including supply and demand, 51 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 51 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. The Company currently maintains all of its debt portfolio in fixed-rate 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. Due to the fact that all of the Company’s debt at year-end has fixed rate interest obligations, there is no current risk due to interest rate fluctuation. The following tables provide information as of September 30, 2004 and 2003 about the Company’s interest rate risk sensitive instruments: I N T E R E S T R AT E R I S K (in thousands) 2005 2006 2007 2008 2009 After 2009 Total Fair Value @ 9/30/04 Fixed Rate Debt Average Interest Rate – – – – $ 25,000 5.5% Variable Rate Debt $ 30,000 $ – $ Average Interest Rate (a) – – – – – – $ – – $ 25,000 $150,000 $200,000 $216,400 5.9% 6.5% 6.3% $ – – $ – – $ 30,000 $ 30,000 – (a) (a) LIBOR plus an increment of .875 to 1.125% depending on certain financial ratios. 52 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 52 I N T E R E S T R AT E R I S K (in thousands) 2004 2005 2006 2007 2008 After 2008 Total Fair Value @ 9/30/03 Fixed Rate Debt Average Interest Rate $ – – $ – – Variable Rate Debt $ 30,000 $ – Average Interest Rate (a) – – $ – – $ – – $ 25,000 $ – $175,000 $ 200,000 $ 226,500 5.5% $ – – – $ – – 6.4% 6.3% $ – $ 30,000 $ 30,000 – (a) (a) LIBOR plus an increment of .875 to 1.125% depending on certain financial ratios. Equity Price Risk. On September 30, 2004, the Company owned stocks in other publicly held companies with a total market value of $240.7 million. The Company’s investments in Atwood Oceanics, Inc., and Schlumberger, Ltd., made up almost 94 percent of the portfolio’s market value at September 30, 2004. Although the Company sold a portion of its position in Schlumber in 2004 and Atwood in the first quarter of 2005, the Company has no specific plans to sell additional securities, but may sell additional securities based on market conditions and other circumstances. 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 $169.5 million at September 30, 2003. 53 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 53 Report of Independent Registered Public Accounting Firm 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, 2004 and 2003, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2004, in conformity with U.S. generally accepted accounting principles. E R N S T & Y O U N G L L P Tulsa, Oklahoma November 23, 2004 54 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 54 Consolidated Statements of Income Years Ended September 30, 2004 2003 2002 REVENUES Operating revenues Income from investments COSTS AND EXPENSES Direct operating costs Depreciation Asset impairment charge General and administrative Interest (in thousands, except per share amounts) $593,326 $507,331 $523,803 27,602 7,953 28,076 620,928 515,284 551,879 416,631 345,537 361,669 94,425 51,516 37,661 12,695 82,513 61,447 – 41,003 12,289 – 36,563 980 612,928 481,342 460,659 Income from continuing operations before income taxes and equity in income (loss) of affiliates 8,000 33,942 91,220 Provision for income taxes Equity in income (loss) of affiliates net of income taxes Income from continuing operations Income from discontinued operations 4,365 14,649 40,573 724 ( 1,420) 3,059 4,359 17,873 53,706 – – 9,811 NET INCOME $ 4,359 $ 17,873 $ 63,517 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 $ 0.09 $ 0.36 $ 1.08 – – 0.19 $ 0.09 $ 0.36 $ 1.27 $ 0.09 $ 0.35 $ 1.07 – – 0.19 $ 0.09 $ 0.35 $ 1.26 Average common shares outstanding (in thousands): Basic Diluted 50,312 50,833 50,039 50,596 49,825 50,345 The accompanying notes are an integral part of these statements. 55 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 55 Consolidated Balance Sheets ASSETS CURRENT ASSETS: September 30, 2004 2003 (in thousands) Cash and cash equivalents $ 65,296 $ 38,189 Accounts receivable, less reserve of $1,265 in 2004 and $1,319 in 2003 Inventories Deferred income taxes Prepaid expenses and other Total current assets 133,262 20,826 4,346 22,156 91,088 22,533 1,935 45,721 245,886 199,466 INVESTMENTS 161,532 158,770 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. 1,531,937 1,490,389 1,228 56,307 93,640 45,004 56,247 87,570 1,683,112 1,679,210 684,438 998,674 621,005 1,058,205 752 1,329 $1,406,844 $1,417,770 56 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 56 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, 2004 2003 (in thousands, except share data) $ — $ 30,000 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: 28,012 31,891 59,903 200,000 194,573 38,258 432,831 5,353 — 85,466 828,763 — 36,252 955,834 41,724 914,110 29,630 28,988 88,618 200,000 183,672 28,229 411,901 5,353 — 83,302 840,776 (10) 33,668 963,089 45,838 917,251 Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Unearned compensation Accumulated other comprehensive income Less treasury stock, 3,083,516 shares in 2004 and 3,388,588 shares in 2003, at cost Total shareholders’ equity TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $1,406,844 $1,417,770 The accompanying notes are an integral part of these statements. September 30, 2002 2001 2000 57 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 57 Consolidated Statements of Shareholders’ Equity 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, 2001 53,529 $5,353 $80,324 $(1,812) $943,105 3,676 $(49,802) $49,309 $1,026,477 Comprehensive Income: Net Income Other comprehensive loss: Unrealized losses on available- for-sale securities, net Derivatives instruments losses, net Minimum pension liability adjustment, net Total other comprehensive loss Total comprehensive income Distribution of Cimarex Energy Co. Stock Cash dividends ($.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 Balance, September 30, 2003 53,529 5,353 83,302 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 Total comprehensive income Cash dividends ($.32 per share) Exercise of stock options Tax benefit of stock-based awards Amortization of deferred compensation Comprehensive Income: Net Income Other comprehensive income (loss): Unrealized gains on available- for-sale securities, net Derivatives instruments amort., net Minimum pension liability adjustment, net Total other comprehensive gain Comprehensive income Cash dividends ($.3225 per share) Exercise of stock options Tax benefit of stock-based awards Amortization of deferred compensation 63,517 (25,449) (68) (7,612) 156 1,466 (190) (152,201) (15,492) (181) 23 2,455 (244) 838,929 3,518 (47,591) 16,180 17,873 15,005 982 1,501 441 372 (16,026) (129) 1,753 180 (10) 840,776 3,389 (45,838) 33,668 4,359 3,721 72 (1,209) (16,372) (305) 4,114 813 1,351 10 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) 2,194 372 180 917,251 4,359 3,721 72 (1,209) 2,584 6,943 (16,372) 4,927 1,351 10 Balance, September 30, 2004 53,529 $5,353 $85,466 $ – $828,763 3,084 $(41,724) $ 36,252 $ 914,110 The accompanying notes are an integral part of these statements. 58 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 58 Consolidated Statements of Cash Flows Years Ended September 30, 2004 2003 (in thousands) 2002 OPERATING ACTIVITIES: Income from continuing operations Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation Asset impairment charge Equity in (income) loss of affiliates before income taxes Amortization of deferred compensation Gain on sales of securities Non-monetary investment (gain) loss Gain on sale of property, plant and equipment Deferred income tax expense 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 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 long-term debt Payments on long-term debt (Decrease) increase in short-term notes Dividends paid 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 used in discontinued operations Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period The accompanying notes are an integral part of these statements. 59 $ 4,359 $ 17,873 $ 53,706 94,425 51,516 (1,168) 10 (22,766) (2,521) (5,377) 5,934 (98) (25,335) 1,707 24,142 (1,618) 2,870 2,323 6,997 131,041 135,400 (88,972) 7,941 — 14,033 (66,998) — — (30,000) (16,222) 4,927 (41,295) — — — — 82,513 — 2,290 180 (5,529) — (3,689) 41,391 336 1,516 251 (29,355) (11,415) (1,281) (166) 1,589 78,631 96,504 (246,301) 6,720 — 18,215 (221,366) 100,000 — 30,000 (16,026) 2,194 116,168 — — — — 61,447 — (5,014) 1,122 (25,551) 1,204 (1,392) 21,147 791 24,148 1,042 24,381 (3,769) 955 2,986 (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) 27,107 38,189 $ 65,296 (8,694) 46,883 $ 38,189 (81,943) 128,826 $ 46,883 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 59 Notes to Consolidated Financial Statements NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES September 30, 2004, 2003 and 2002 PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and 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 con- tinuing operations of the Company (see Note 2). Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. 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 $(2.2) million, $.4 million, and $(5.5) million, for 2004, 2003, and 2002, 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. 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 2004, 2003, and 2002 was $.5 million, $1.8 million, and $2.5 million, respectively. 60 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 60 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. CASH AND CASH EQUIVALENTS Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which mature within three months from the date of purchase. INVENTORIES AND SUPPLIES Inventories and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventories and supplies are valued at the lower of cost (moving average or actual) or market value. DRILLING REVENUES Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and expenses are recognized as work progresses. For certain contracts, the Company receives lump-sum payments for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct costs. RENT REVENUES The Company enters into leases with tenants in its rental properties consisting primarily of retail and multi-tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings range from one to ten years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants’ sales volume. The Company’s rent revenues are as follows: Years ended September 30, Minimum rents Overage and percentage rents 2004 $ 7,490 $ 1,207 2003 (in thousands) $ 7,333 $ 768 2002 $ 6,980 $ 915 61 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 61 At September 30, 2004, minimum future rental income to be received on noncancelable operating leases were as follows (in thousands): Fiscal Year 2005 2006 2007 2008 2009 Thereafter Total Amount $ 6,525 5,654 5,103 4,092 3,175 7,765 $ 32,314 INVESTMENTS The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. Net income in 2004 includes approximately $1.5 million, $0.03 per share on a diluted basis, on gains related to non-monetary transactions within the Company’s available-for-sale investment portfolio which were accounted for at fair value. Net income in 2002 includes a loss of approximately $0.5 million, $0.01 per share on a diluted basis, resulting from the Company’s assessment that the decline in market value of certain available-for-sale securities below their financial cost basis was other than temporary. There were no losses in 2004 and 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 Company recognizing its proportionate share of the income or loss of each investee. The Company owned approximately 21.7 percent of Atwood Oceanics, Inc. (Atwood) at both September 30, 2004 and 2003. The quoted market value of the Company's investment was $142.6 million and $72 million at September 30, 2004 and 2003, respectively. Retained earnings at September 30, 2004 and 2003 includes approximately $29 million and $28 million, respectively, of undistributed earnings of Atwood. In October 2004, the Company sold 1,000,000 shares of its position in Atwood as part of a 2,175,000 share public offering of Atwood. The sale generated approximately $16.5 million ($0.32 per diluted share) of net income for the first quarter of fiscal 2005. With its remaining 2,000,000 shares of Atwood, the Company will own approximately 13.3 percent of Atwood. The Company will continue to account for Atwood on the equity method as the Company continues to have significant influence through its board of director seats. 62 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 62 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 $ 163,454 155,867 $ 7,587 2002 (in thousands) $ 144,766 157,568 $ (12,802) 2001 $ 149,157 120,872 $ 28,285 net income (loss), net of income taxes $ 724 $ (1,414) $ 4,206 Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity $ 92,966 $ 72,182 $ 71,813 405,970 60,053 167,294 271,589 447,464 40,504 215,757 263,385 372,717 24,416 143,981 276,133 Helmerich & Payne, Inc.’s investment $ 57,824 $ 56,655 $ 58,937 INCOME TAXES Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities. OTHER POST EMPLOYMENT BENEFITS The Company sponsors a health care plan that provides post retirement medical benefits to retired employees. Employees who retire after November 1, 1992 and elect to participate in the plan pay the entire estimated cost of such benefits. The Company has accrued a liability for estimated worker’s compensation claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material. EARNINGS PER SHARE Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per share includes the dilutive effect of stock options and restricted stock. EMPLOYEE STOCK-BASED AWARDS Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Fixed plan common stock options generally do not result in compensation expense, because the exercise price of the options issued by the Company equals 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 6. 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.” 63 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 63 September 30, 2004 2003 (in thousands, except per share amounts) 2002 Net income, as reported $ 4,359 $ 17,873 $ 63,517 Add: Stock-based employee compensation expense included in the Consolidated Statements of Income, net of related tax effects 6 112 909 Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related tax effects (4,172) ( 4,387) ( 3,354) Pro forma net income $ 193 $ 13,598 $ 61,072 Earnings per share: Basic-as reported Basic-pro forma Diluted-as reported Diluted-pro forma $ 0.09 $ 0.00 $ 0.09 $ 0.00 $ 0.36 $ 0.27 $ 0.35 $ 0.27 $ 1.27 $ 1.23 $ 1.26 $ 1.21 These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years. TREASURY STOCK Treasury stock purchases are accounted for under the cost method whereby the 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. NOTE 2 DISCONTINUED OPERATIONS 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 past and future periods, including all taxes arising from the Cimarex business prior to the time Cimarex was formed, and agrees to hold the Company harmless in respect of those 64 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 64 taxes. Cimarex is entitled to receive all refunds and credits of taxes previously paid with respect to the exploration and production business. Cimarex will not receive the benefit of any loss or similar tax attribute arising during the time that losses from the Cimarex business are included in the Company’s consolidated federal income tax return. The Company remains responsible for all taxes related to the business of the Company other than the exploration and production business and has agreed to indemnify Cimarex in respect of any liability for any such taxes. Summarized results of discontinued operations for the year ended September 30, 2002 is as follows: September 30, Revenues Income from operations: Income before income taxes Tax provision Income from discontinued operations 2002 (in thousands) $172,827 15,138 5,327 $ 9,811 NOTE 3 IMPAIRMENT OF LONG-LIVED ASSETS The Company periodically evaluates long-lived assets when events or circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. Changes that could trigger such an assessment may include a significant decline in revenue or cash margin per day, extended periods of low rig utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts, and/or overall general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. In evaluating the Company’s U.S. Offshore Platform business in the Gulf of Mexico, indicators of impairment were present, including declines in revenue and margin per day, industry and Company platform rig utilization, and bid activity. As the result of the declining financial trends and the generally unfavorable market conditions in the Gulf of Mexico, management completed an analysis of the general market conditions in the offshore platform rig business and the prospective market demand for each of the 12 offshore rigs owned by the Company. Based on this analysis, management determined that the carrying value of certain offshore rigs exceeded the estimated undiscounted future cash flows associated with these assets; therefore, an impairment charge was required. The amount of the impairment charge represented the difference between the estimated fair value of the asset and its carrying value. Because quoted market prices are not available for offshore platform rigs, the fair value was determined based on estimated discounted future cash flows and rig utilization. Cash flows were 65 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 65 estimated by management considering factors such as prospective market demand, recent changes in technol- ogy and its effect on each rig’s marketability and cash investment required, suitability of rig size and makeup to existing platforms, and new competitive dynamics due to lower industry utilization. Based on its analysis, the Company recorded a $51.5 million pre-tax impairment charge to the Offshore Platform segment in the fourth quarter of fiscal 2004. In conjunction with the impairment charge, the Company retired rig 108 at September 30, 2004, which brings the number of available platform rigs to eleven. The Company also reduced the depreciable lives of five platform rigs to four years and the salvage value of each of the offshore rigs to $1.0 million. As a result of the impairment charge and the change in depreciable lives and salvage values, depreciation expense in future years in the Offshore Platform segment will be reduced by approximately $2.0 million a year. NOTE 4 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 2004, the Company had $200 million in long-term debt outstanding at fixed rates and maturities as summarized in the following table. (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 capitaliza- tion. The proceeds of the debt issuances were used to repay $50 million of outstanding debt, to fund the Company’s rig construction program and for other general corporate purposes. This debt is held by various entities including $8.0 million held by a company affiliated with one of the Company’s Board members. At September 30, 2004, the Company had a committed unsecured line of credit totaling $50 million. Letters of credit totaling $13 million were outstanding against the line, leaving $37 million available to borrow. Under terms of the line of credit, the Company must maintain certain financial ratios including debt to total capitaliza- tion and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of liquidity and tangible net worth. The interest rate varies based on LIBOR plus .875 to 1.125 percent or prime minus 1.75 percent to prime minus 1.50 percent depending on ratios described above. 66 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 66 NOTE 5 INCOME TAXES The components of the provision (benefit) for income taxes from continuing operations are as follows: Years Ended September 30, 2004 2003 (In thousands) 2002 CURRENT: Federal Foreign State DEFERRED: Federal Foreign State $ (5,997) $ (34,495) $ 13,324 4,622 (194) (1,569) 4,037 1,902 (5) 5,934 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 TOTAL PROVISION: $ 4,365 $ 14,649 $ 40,573 The amounts of domestic and foreign income (loss) from continuing operations are as follows: Years Ended September 30, 2004 Income (loss) from continuing operations before income taxes and equity in income (loss) of affiliates: Domestic Foreign $ (2,972) 10,972 $ 8,000 2003 (In thousands) $ 31,164 2,778 $ 33,942 2002 $ 82,012 9,208 $ 91,220 The components of the Company’s net deferred tax liabilities are as follows: September 30, 2004 2003 2000 (In thousands) Deferred tax liabilities: Property, plant and equipment Available-for-sale securities Equity investments Total deferred tax liabilities Deferred tax assets: Pension reserves Insurance reserves Net operating loss carryforwards Alternative minimum tax credit carryforwards Financial accruals Other Total deferred tax assets Net deferred tax liabilities $ 188,409 28,203 17,793 234,405 7,283 4,452 21,077 2,542 7,574 1,250 44,178 $190,227 $164,078 25,106 17,349 206,533 4,918 3,688 4,074 5,333 4,446 2,337 24,796 $181,737 Reclassifications have been made to the fiscal 2003 balances for certain components of deferred tax assets and liabilities in order to conform to the current year’s presentation. 67 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 67 Deferred tax assets and liabilities included in the consolidated balance sheets are as follows: September 30, 2004 2003 Other current assets Deferred income taxes Total $ 4,346 (194,573) $ (190,277) (In thousands) $ 1,935 (183,672) $(181,737) As of September 30, 2004, the Company’s federal and state net operating loss carryforwards for income tax purposes were approximately $43 million and $66 million, respectively. If not utilized, the federal net operating loss carryforwards will expire in fiscal 2024, and the state net operating loss carryforwards will begin to expire in fiscal 2008. 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, 2004 2003 2002 U.S. Federal income tax rate Effect of foreign taxes State income taxes Other Effective income tax rate NOTE 6 SHAREHOLDERS’ EQUITY 35% 18 — 2 55% 35% 4 4 — 43% 35% 7 2 — 44% In December 2001, the board of directors authorized the repurchase of up to 2,000,000 shares per calendar year of the Company’s common stock in the open market or private transactions. The repurchased shares will be held in treasury and used for general corporate purposes including use in the Company’s benefit plans. The Company did not repurchase any shares in fiscal 2004, 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. In March 2001, the Company adopted the 2000 Stock Incentive Plan (the “Stock Incentive Plan”). The Stock Incentive Plan was effective December 6, 2000 and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options for up to 3,000,000 shares of the Company’s common stock at an exercise price not less than the fair market value of the common stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock awards. There were no restricted stock grants in fiscal 2004, 2003, or 2002. On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders. The distribution was recorded as a dividend and resulted in a decrease to consolidated shareholders’ equity of approximately $152.2 million. Any options held by Cimarex employees at the distribution date were automatically forfeited per the terms of the Company’s stock incentive plans. Both vested and unvested options held by remaining partici- pants 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 spinoff 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. 68 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 68 The following summary reflects the stock option activity for the Company’s common stock and related information for 2004, 2003, and 2002 (shares in thousands): Outstanding at October 1, Granted Exercised Adjustment for Cimarex spinoff Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant Options 4,327 469 (305) — (34) 4,457 2,997 1,158 2004 2003 2002 Weighted-Average Exercise Price Options Weighted-Average Exercise Price Options Weighted-Average Exercise Price $21.41 3,875 $20.28 3,136 $25.78 24.18 16.15 — 25.38 $22.03 $20.62 611 (130) — (29) 4,327 2,575 1,597 27.74 16.93 — 23.85 $21.41 $19.34 820 (181) 926 29.89 19.61 — (826) 28.15 3,875 1,935 2,195 $20.28 $19.07 The following table summarizes information about stock options at September 30, 2004 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $10.22 to $12.79 $18.83 to $22.66 $24.59 to $28.04 $10.22 to $28.04 Options 685 1,550 2,222 4,457 Weighted-Average Remaining Life Weighted-Average Exercise Price 2.9 5.6 6.8 5.8 $11.86 $20.81 $26.01 $22.03 Options 685 1,174 1,138 2,997 Weighted-Average Exercise Price $11.86 $20.22 $26.30 $20.62 The weighted-average fair value of options at their grant date during 2004, 2003, and 2002 was $10.24, $10.72, and $12.47, respectively. The estimated fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model: Risk-free interest rate Expected stock volatility Dividend yield Expected years until exercise 2004 3.7% 44% .8% 5.5 2003 3.1% 48% .8% 4.5 2002 4.0% 48% .8% 4.5 On September 30, 2004, the Company had 50,445,436 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 69 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 69 days after a person acquires 15 percent or more of the outstanding common stock or ten business days following the commencement of a tender offer or exchange offer that would result in a person owning 15 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 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 7 EARNINGS PER SHARE A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: Basic weighted-average shares Effect of dilutive shares: Stock options Restricted stock Diluted weighted-average shares 2004 50,312 521 — 521 50,833 2003 (in thousands) 50,039 555 2 557 50,596 2002 49,825 508 12 520 50,345 At September 30, 2004, options to purchase 1,027,680 shares of common stock at a weighted-average price of $27.84 were outstanding, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 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. 70 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 70 NOTE 8 FINANCIAL INSTRUMENTS The Company had $200 million of long-term debt outstanding at September 30, 2004 which had an estimated fair value of $216.4 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 the cost of borrowings, if any, would approximate fair value. The estimated fair value of the Company’s available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1): Equity Securities: September 30, 2004 September 30, 2003 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $ 27,811 $ 33,300 $ 70,448 $ 64,276 $ 170 $ 0 $ 98,089 $ 97,576 During the years ended September 30, 2004, 2003, and 2002, marketable equity available-for-sale securities with a fair value at the date of sale of $30.9 million, $18.2 million, and $46.7 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $22.8 million, $8.6 million, and $25.9 million, respectively, and the gross realized losses totaled $7 thousand, $3.1 million and $232 thousand, respectively. 71 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 71 NOTE 9 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The table below presents changes in the components of accumulated other comprehensive income (loss). Unrealized Appreciation (Depreciation) on Securities Interest Rate Swap Minimum Pension Liability Total (in thousands) Balance at September 30, 2001 $ 50,295 $ (986) $ – $ 49,309 2002 Change: Pre-income tax amount Income tax provision Amortization of swap (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) Balance at September 30, 2003 2004 Change: Pre-income tax amount Income tax provision Amortization of swap (3,428) 15,005 39,851 31,420 (11,940) (net of $45 income tax benefit) – Realized gains in net income (net of $9,659 income tax) (15,759) 3,721 (127) 48 11 – (68) (1,054) – – 982 – 982 (72) – – 72 – 72 (12,277) 4,665 (28,632) 10,880 – – (7,612) (7,612) 2,421 (920) – – 1,501 (6,111) (1,951) 742 – – (1,209) 11 (15,388) (33,129) 16,180 32,152 (12,218) 982 (3,428) 17,488 33,668 29,469 (11,198) 72 (15,759) 2,584 Balance at September 30, 2004 $ 43,572 $ – $ (7,320) $ 36,252 72 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 72 NOTE 10 EMPLOYEE BENEFIT PLANS The Company maintains a noncontributory defined pension plan for substantially all U.S. employees who meet certain age and service requirements. In July 2003, the Company revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan”) to 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 Pension Plan frozen. The following table and other information in this footnote provide information at September 30 as to the Company sponsored domestic defined pension plan as required by SFAS No. 132 (Revised 2003), “Employers’ Disclosures About Pensions and Other Postretirement Benefits.” Change in benefit obligation: Years Ended September 30, 2004 2003 (in thousands) Benefit obligation at beginning of year $ 71,174 $ 68,134 Service cost Interest cost Curtailments Actuarial loss Benefits paid 3,943 4,403 — 5,985 (3,283) 5,401 4,423 (8,444) 6,269 (4,609) Benefit obligation at end of year $ 82,222 $ 71,174 Change in plan assets: Years Ended September 30, 2004 (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 $ 53,635 6,298 (3,283) $ 56,650 $ (25,572) 18,211 1 (11,807) $ (19,167) 2003 $ 48,286 9,958 (4,609) $ 53,635 $ (17,539) 15,052 20 (9,856) $ (12,323) Weighted-average assumptions: Discount rate Years Ended September 30, 2004 5.75% Expected return on plan assets Rate of compensation increase 8.00% 5.00% 73 2003 6.25% 8.00% 5.00% 2002 6.75% 8.00% 5.00% 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 73 The Company anticipates that no funding of its Pension Plan will be required in fiscal 2005. COMPONENTS OF NET PERIODIC PENSION EXPENSE: Years Ended September 30, 2004 Service cost Interest cost Expected return on plan assets Amortization of prior service cost Amortization of transition asset Recognized net actuarial loss Curtailment gain Net pension expense 2003 (in thousands) $ 5,401 4,423 ( 3,807) 180 — 1,550 84 2002 $ 4,769 3,835 ( 4,804) 238 (540) 120 — $ 3,944 4,403 (4,232) 19 — 760 — $ 4,894 $ 7,831 $ 3,618 The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter. 2005 2006 2007 2008 2009 2010-2014 Total Years Ended September 30, $ 3,967 $ 4,112 $ 4,134 $ 4,201 $ 4,278 $23,515 $44,207 (in thousands) Included in the Pension Plan is an unfunded supplemental executive retirement plan. The accumulated benefit obligation for the defined Pension Plan was $75.7 million, $66.1 million and $55.7 million at September 30, 2004, 2003, and 2002, respectively. The Company evaluates the Pension Plan to determine whether any additional minimum liability is required. As a result of changes in the interest rates, an adjustment to the minimum pension liability was required. The adjustment to the liability is recorded as a charge to accumulated other comprehensive loss, net of tax, in shareholders’ equity in the consolidated balance sheets. INVESTMENT STRATEGY AND ASSET ALLOCATION The Company’s investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Plan while providing adequate security to meet the benefits promised under the Plan. The Company maintains a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any one investment. In determining the appropriate asset mix, the Company’s financial strength and ability to fund potential shortfalls are considered. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the Plans’ investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes. 74 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 74 The target allocation for 2005 and the asset allocation for the domestic Pension Plan at the end of fiscal 2004 and 2003, by asset category, follows: Target Allocation Percentage of Plan Assets At September 30, Asset Category U.S. equities International equities Fixed income Real estate and other Total 2005 56% 14 25 5 100% 2004 57% 15 27 1 2003 57% 15 26 2 100% 100% The fair value of plan assets was $56.7 million and $53.6 million at September 30, 2004 and 2003, respectively, and the expected long-term rate of return on these plan assets was 8% in 2004 and 8% in 2003. DEFINED CONTRIBUTION PLAN Substantially all employees on the United States payroll of the Company may elect to participate in the Company sponsored 401(k)/Thrift 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 $5.6 million, $5.6 million, and $5.2 million in 2004, 2003, and 2002, respectively. NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in the Company’s reserve for bad debt for 2004 and 2003: Reserve for bad debt: Balance at October 31, Provision for bad debt Write-off of bad debt Balance at September 30, 2004 2003 (in thousands) $ 1,319 15 (69) $ 1,265 $ 1,337 45 (63) $ 1,319 75 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 75 Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following: September 30, 2004 2003 (in thousands) Accounts receivable: Trade receivables Investment sales receivables Prepaid expenses and other: Time deposits Income tax asset Deferred mobilization Restricted cash Other Accrued liabilities: Taxes payable – operations Workers compensation claims Payroll and employee benefits Deferred income / prepays Other $116,423 16,839 $133,262 $ 350 5,831 2,846 2,000 11,129 $ 22,156 $ 6,531 2,877 8,678 2,844 10,961 $ 31,891 $ 91,088 — $ 91,088 $ 322 32,619 2,993 — 9,787 $ 45,721 $ 8,386 2,820 6,768 1,535 9,479 $ 28,988 NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2004 2003 (in thousands) 2002 Cash payments: Interest paid, net of amount capitalized Income taxes paid $ 12,653 $ 7,010 $ 11,375 $ 5,838 $ 477 $ 9,779 76 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 76 NOTE 13 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 established 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 management’s knowledge of customer accounts. No significant credit losses have been experienced by the Company. SELF-INSURANCE The Company self-insures a significant portion of its expected losses under its worker’s compensation, general, and automobile liability programs in the United States. Insurance coverage has been purchased for individual claims that exceed $2 million. The Company records estimates for incurred outstanding liabilities for unresolved worker’s compensation, general liability claims and for claims that are incurred but not reported. Estimates are based on historic experience and statistical methods that the Company believes are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim 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 operat- ing results and financial position. 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 billings to the Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar, PDVSA typically pays all accounts owed in bolivars. The Company, historically, has been able to convert the bolivars received in payment of the U.S. dollar-based billings into dollars in a timely manner. 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. In compliance with applicable 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. In January 2004 the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars 77 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 77 and the remittance of those U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S. based parent. The Company was able to remit $8.8 million of such dividends in January 2004. This reduced the Company’s exposure to currency devaluation in Venezuela. 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. As a result of the 20 percent devaluation of the bolivar during fiscal 2004 (from September 2003 through August 2004), the Company experienced total devaluation losses of $1.9 million during that same period. This 20 percent devaluation loss may not be reflective of the potential for future devaluation losses because of the exchange controls that are currently in place. There have been recent press reports of a potential devaluation in calendar 2005. However, the exact amount and timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2005 activity levels are similar to fiscal 2004 and if a 10 percent to 20 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $1.2 million to $2.3 million. In late August 2003, the Venezuelan state petroleum company agreed, on a go-forward 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. Venezuela continues to experience significant 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. 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, 2004, the Company did not have any material commitments for the purchase of drilling equipment. 78 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 78 LEASES In May 2003, the Company signed a six-year lease for approximately 114,000 square feet of office space near downtown Tulsa, Oklahoma. The Company also conducts certain operations in leased premises and leases telecommunication equipment. Future minimum lease payments required under noncancelable operating leases as of September 30, 2004 are as follows (in thousands): Fiscal Year 2005 2006 2007 2008 2009 Thereafter Total Amount $ 2,542 2,261 1,844 1,412 1,408 462 $ 9,929 Total rent expense was $2.0 million, $1.1 million and $1.0 million for 2004, 2003 and 2002, 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; 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 reflection 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. 79 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 79 Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2004, 2003, and 2002 is shown in the following table: (in thousands) 2004: Contract Drilling U.S. Land U.S. Offshore Platform International Services Real Estate Other Eliminations Total 2003: Contract Drilling U.S. Land U.S. Offshore Platform International Services Real Estate Other Eliminations Total 2002: Contract Drilling $ 347,793 84,993 150,698 583,484 9,842 27,602 — $ 620,928 $ 273,993 112,633 109,812 496,438 10,893 7,953 — $ 515,284 U.S. Land $ 231,637 U.S. Offshore Platform 132,249 151,392 International Services 515,278 8,525 28,076 — $ 551,879 Real Estate Other Eliminations Total External Sales Inter- Segment Total Sales Operating Profit (loss) Depreciation Total Assets Additions to Long-Lived Assets $ 68,680 1,512 9,513 79,705 3,538 5,729 — $ 88,972 $ 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 $ — — — — 897 — (897) $ — $ — — — — 1,439 — (1,439) $ — $ 809 — — 809 1,491 — (2,300) $ — $ 347,793 84,993 150,698 583,484 10,739 27,602 (897) $ 620,928 $ 273,993 112,633 109,812 496,438 12,332 7,953 (1,439) $ 515,284 $ 37,323 (34,873) 14,036 16,486 4,242 — — $ 20,728 $ 18,565 36,306 5,149 60,020 6,569 — — $ 66,589 $ 56,528 12,107 20,530 89,165 2,253 3,007 — $ 742,642 102,557 261,893 1,107,092 33,044 266,708 — $ 94,425 $1,406,844 $ 44,726 12,799 20,092 77,617 2,535 2,361 — $ 730,642 170,580 243,918 1,145,140 31,472 241,158 — $ 82,513 $1,417,770 $ 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 80 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 80 The following table reconciles segment operating profit to income before taxes and equity in income (loss) of affiliates as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, 2004 2003 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 $ 20,728 $ 66,589 27,602 (24,496) (12,695) (3,007) (132) (12,728) 7,953 (25,650) (12,289) (2,361) (300) (32,647) 2002 $ 87,373 28,076 (20,391) (980) (2,147) (711) 3,847 $ 8,000 $ 33,942 $ 91,220 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, 2004 2003 2002 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $ 470,230 56,279 43,540 3,704 47,175 $ 620,928 $ 799,207 85,336 46,809 9,336 57,986 $ 998,674 $ 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 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 10.8 percent, 15.7 percent, and 16.3 percent of the total consolidated revenues during the years ended September 30, 2004, 2003, and 2002, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 10.7 percent, 14.6 percent, and 14.7 percent of total consolidated revenues in the years ended September 30, 2004, 2003, and 2002, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.4 percent, 11.5 percent, and 12.3 percent of total consolidated revenues in the years ended September 30, 2004, 2003, and 2002, respectively. Collectively, the receivables from these customers were approximately $28.6 million and $36.0 million at September 30, 2004 and 2003, respectively. 81 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 81 NOTE 16 SUBSEQUENT EVENT In November 2004, the Company sold two conventional 2,000 horsepower rigs from its U.S. land fleet for a total of $23.9 million. NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2004 Revenues Asset impairment charge Gross profit (loss) Net income (loss) Basic net income (loss) per common share: Diluted net income (loss) per common share: 2003 Revenues Gross profit Net income Basic net income per common share: Diluted net income per common share: $ 140,458 $ 151,186 $ 147,874 $ 181,410 — 24,663 6,588 .13 .13 — 23,124 6,048 .12 .12 — 18,638 4,347 .09 .09 51,516 (8,069) (12,624) (.25) (.25) 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 Gross profit (loss) 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 first quarter of 2004 has been adjusted upward from amounts previously reported by approximately $1.0 million ($0.02 per share, on a diluted basis) to reflect a non-monetary gain on the conversion of shares of common stock of a company investee pursuant to that investee being acquired. All future public filings will reflect this change. In the fourth quarter of fiscal 2004, the net loss includes an after-tax gain on sale of available-for-sale securities of $8.1 million, $0.16 per share, on a diluted basis. In the fourth quarter of fiscal 2004, the net loss includes an after-tax asset impairment charge of approximately $32 million, $0.63 per share, on a diluted basis. 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 from affiliates of $2.0 million, $0.04 per share, on a diluted basis. 82 04-HP-876_newMDA.qxd 12/15/04 3:04 PM Page 82 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 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**(***) 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, Retired AT&T Wireless Services, Inc. Basking Ridge, New Jersey * Member, Audit Committee ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee 83 Stockholders’ Meeting The annual meeting of stockholders will be held |on March 2, 2005. 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, 2005. Stock Exchange Listing Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol “HP.” The newspaper abbreviation most commonly used for financial reporting is “HelmP.” Options on the Company’s stock are also traded on the New York Stock Exchange. Stock Transfer Agent and Registrar As of December 3, 2004, there were 860 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. Our Transfer Agent is responsible for our share- holder 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 Available 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 confidentially 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. Annual CEO Certification The annual CEO Certification required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual was provided to the New York Stock Exchange on or about March 12, 2004. 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 

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