Helmerich & Payne Annual Report 2005

Plain-text annual report

Helmerich & Payne, Inc. is the holding Company H e l m e r i c h & P a y n e , I n c . for Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore platform operations in the United States, South America, and Africa. Holdings also include commercial real estate properties in the Tulsa, Oklahoma, area and an energy-weighted portfolio of publicly-traded securities valued at approximately $293 million as of September 30, 2005. F I N A N C I A L H I G H L I G H T S Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets Years Ended September 30, 2005 2004 (in thousands, except per share amounts) $ 800,726 127,606 2.45 .33 86,805 1,663,350 $ 589,056 4,359 .09 .3225 90,212 1,406,844 To the Co-owners of Helmerich & Payne, Inc.: The Company’s 2005 performance represents an all-time high in our 85-year history in terms of income from continuing operations. We reached another important milestone with the announcement of our 50th new-build order for FlexRigsT. Seventy-ﬁve percent of our ﬂeet has been built since 1995, and these new rigs will only improve on that strength. Our goal can be plainly stated and is consistent with a long-term, Company-wide resolve: To provide our customers with the most innovative and advanced rigs in the industry for the purpose of driving their well costs down. Combined with best in ﬁeld execution − performance, safety, and reliability − we believe H&P delivers a compelling value proposition. Those satisﬁed customers, in turn, provide us with unique growth opportunities and improved shareholder returns. The operators’ willingness to make long-term commitments provides an encouraging lens on how customers perceive the unusual and potential longevity of this current cycle. Our ﬁnancial strength and ample liquidity also enable us to fund organic growth going forward. The meaningfulness of that internally generated growth is underscored by these 50 new-builds, which will increase our total domestic land ﬂeet by more than 50 percent. Over 70 percent of our U.S. land ﬂeet will then be comprised of these 100 FlexRigs. That distinctive ﬂeet TFlexRig is a registered trademark of Helmerich & Payne, Inc. proﬁle allows us to present our customers an across the board quality offering and ﬂeet uniformity that I believe is unmatched in the land drilling industry. U.S. Land Operations Compared to last year, the Company had approximately ten additional rigs working for a full year in 2005, as average utilization increased from 87 to 94 percent in our U.S. land operations segment. At the close of 2005, the segment had only one uncommitted rig, and its ﬂeet was 97 percent utilized. Revenue and operating income increased by 52 percent and 363 percent, respectively, over the prior year. Dayrates increased substantially in 2005, and they’ve continued to escalate during the ﬁrst quarter of 2006. The Company’s 32 FlexRig3s consistently lead the industry in ﬁeld performance and strong pricing. The Company also announced 50 additional new-build orders, each with a three or four-year term contract. These new rigs represent a 100 percent expansion of our existing FlexRig ﬂeet and a 56 percent expansion of our U.S. land rig ﬂeet. Prices for drilling machinery are increasing drastically, and the Company is fortunate to have 50 FlexRigs in the ﬁeld today and a timely start on the next 50. Managing our assembly operation allows us to better control total cost, delivery schedule, and ﬁeld performance. We plan to deliver the ﬁrst new FlexRig in December and to continue delivering FlexRigs at a rate of two per month. Our plans are to increase the production rate to three FlexRigs per month in the spring and to four FlexRigs per month in the summer of 2006. U.S. Offshore Operations Despite a slowdown in recent years, the Gulf of Mexico remains a critical North American producing basin. Hurricanes Katrina and Rita, and a year before them, Ivan, caused signiﬁcant damage to the oil and gas infrastructure in the Gulf, and this has caused considerable uncertainty in commodity markets and with future investment plans. The Company had ﬁve rigs active on customers’ offshore platforms at the close of ﬁscal 2005, including H&P Rig 201, which was signiﬁcantly damaged by Hurricane Katrina. We do not anticipate that Rig 201 will return to service during 2006. Revenue increased only slightly in 2005, as rig activity was essentially unchanged from 2004. Operating income was $17.7 million in 2005, compared with a loss in 2004, which was due primarily to an asset impairment charge. Three rigs were mobilized in the last quarter of 2005 and have commenced drilling operations during the ﬁrst quarter of 2006. Another rig is committed and is expected to start drilling operations during the second ﬁscal quarter of 2006. The two remaining rigs have been bid-on projects that could begin operations by the fourth quarter of 2006. International Operations At the close of the year, the Company had 12 rigs in Venezuela, eight in Ecuador, and two each in Argentina, Bolivia, and Colombia. The Company also has a management contract for a platform rig offshore Equatorial Guinea, West Africa. Approximately 21 land rigs worked the full year, compared with 17 rigs in 2004. Accordingly, international revenue and operating income increased 19 percent and 56 percent, respectively, for the year. Ecuador and Venezuela continue to be the most active markets and Colombia and Argentina experienced some encouraging growth in 2005 as well. Two idle rigs will begin working in Chile and Argentina during the ﬁrst quarter of 2006, and two more rigs will commence operations in Venezuela and Argentina during the second quarter. In addition to South America, the Company continues to pursue other international opportunities. Summary The progress made in 2005 is a credit to the inspiration, dedication, and hard work of our employees. I want to thank all of our people for their effort and also express appreciation to George Dotson, who will retire March 1, 2006, for over 35 years of invaluable service and leadership to the Company. Sincerely, Hans Helmerich President December 7, 2005 Financial & Operating Review Years Ended September 30, 2005 2004 2003 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues Operating Costs Depreciation** General and Administrative Expense Operating Income (loss) Interest, Dividend, and Other Income Income from Investment and Asset Sales Interest 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 †All data excludes discontinued operations except net income. **2004 includes an asset impairment of $51,516 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 – U. S. Land – FlexRigs U. S. Land – Highly Mobile U. S. Land – Conventional U. S. Offshore Platform International Total Rig Fleet Rig Utilization Percentage – U. S. Land – FlexRigs U. S. Land – Highly Mobile U. S. Land – Conventional U. S. Land – All Rigs U. S. Offshore Platform International $ 800,726 484,231 96,274 41,015 179,206 5,574 40,519 12,642 127,606 127,606 $ 589,056 417,716 145,941 37,661 (12,262) 2,162 30,795 12,695 4,359 4,359 $ 504,223 346,259 82,513 41,003 34,448 2,565 9,218 12,289 17,873 17,873 2.45 2.45 .09 .09 .35 .35 $ 288,752 410,316 178,452 981,965 1,663,350 200,000 1,079,238 86,805 $ 65,296 185,427 161,532 998,674 1,406,844 200,000 914,110 90,212 $ 38,189 110,848 158,770 1,058,205 1,417,770 200,000 917,251 242,912 50 12 29 11 26 128 100 99 82 94 53 77 48 11 28 11 32 130 99 91 67 87 48 54 43 11 29 12 32 127 97 89 58 81 51 39 2002 2001 2000 1999 1998 1997 1996 1995 $ 523,418 362,133 61,447 36,563 63,275 2,713 26,212 980 53,706 63,517 $ 528,187 331,063 49,532 28,180 119,412 9,876 5,390 1,701 80,467 144,254 $ 383,898 249,318 77,317 23,306 33,957 19,540 14,164 2,730 36,470 82,300 $ 430,475 288,969 70,092 24,629 46,785 2,823 4,786 5,389 32,115 42,788 $ 476,750 321,798 58,187 21,299 75,466 5,899 41,032 336 80,790 101,154 $351,710 227,921 48,291 15,636 59,862 5,779 6,575 34 48,801 84,186 $275,096 185,210 39,592 15,222 35,072 5,381 230 678 25,844 72,566 $227,646 159,073 37,364 14,019 17,190 6,455 6,752 407 18,464 9,751 1.07 1.26 1.58 2.84 .73 1.64 .65 .86 1.60 2.00 .97 1.67 .52 1.46 .38 .20 $ 46,883 105,852 150,175 897,445 1,227,313 100,000 895,170 312,064 $ 128,826 223,980 203,271 650,051 1,300,121 50,000 1,026,477 184,668 $ 107,632 179,884 307,425 526,723 1,200,854 50,000 955,703 65,820 $ 21,758 82,893 240,891 553,769 1,073,465 50,000 848,109 78,357 $ 24,476 49,179 200,400 548,555 1,053,200 50,000 793,148 217,597 $ 27,963 65,802 323,510 392,489 987,432 — 780,580 114,626 $ 16,892 48,128 229,809 329,377 786,351 — 645,970 83,411 $ 19,543 50,038 156,908 286,678 707,061 — 562,435 89,709 26 11 29 12 33 111 96 97 70 84 83 51 13 11 25 10 37 96 100 89 99 97 98 56 6 10 22 10 40 88 99 95 77 85 94 47 6 11 23 10 39 89 79 90 61 69 95 53 6 7 23 10 44 90 100 100 92 94 99 88 — 7 22 9 39 77 — 100 99 99 63 91 — 7 23 11 36 77 — 87 88 88 70 85 — 8 22 11 35 76 — 76 72 73 66 84 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 0 5 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 F O R M 1 0 - 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, 2005 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 (State or other jurisdiction of incorporation or organization) 73-0679879 (I.R.S. employer identiﬁcation no.) 1437 S. BOULDER AVE., SUITE 1400, TULSA, OKLAHOMA 74119-3623 (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 [ ] Indicate by check mark whether the Registrant is a shell company (as deﬁned in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] At March 31, 2005, the aggregate market value of the voting stock held by non-afﬁliates was $1,945,419,202. Number of shares of common stock outstanding at December 2, 2005: 52,011,465. 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, 2005 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 1, 2006 10-K Parts Parts I and II Part III D I S C L O S U R E R E G A R D I N G F O R W A R D - L O O K I N G S T A T E M E N T S THIS REPORT INCLUDES “FORWARD-LOOKING STATEMENTS” WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT’S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS “MAY”, “WILL”, “EXPECT”, “INTEND”, “ESTIMATE”, “ANTICIPATE”, “BELIEVE”, OR “CONTINUE” OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT’S EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION “RISK FACTORS” BEGINNING ON PAGE 7, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 32 THROUGH 56 OF THE COMPANY’S ANNUAL REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. PART I I T E M 1 . B U S I N E S S Helmerich & Payne, Inc. (the “Company”), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. The Company is primarily engaged in contract drilling of oil and gas wells for others. The contract drilling business accounts for 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 centralized ﬁnance division, which handles all accounting, information technology, budgeting, insurance, cash management, and related activities. The Company’s contract drilling business is composed of three business segments: 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 seven international locations during ﬁscal 2005: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Equatorial Guinea, and Hungary. In addition, the Company provided drilling consulting services for one customer 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 business. The Company does not own any common stock of Cimarex Energy Co. C O N T R A C T D R I L L I N G The Company believes that it is one of the major land and offshore platform drilling contractors in the western hemisphere. Operating principally in North and South America, the Company specializes in medium to deep drilling in major oil and 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 2005, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers. BP plc, ExxonMobil Corporation, and Petroleos de Venezuela S.A. (respectively, “BP”, “ExxonMobil” and “PDVSA”), including their afﬁliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for BP and ExxonMobil on a world-wide basis and PDVSA in Venezuela. Revenues from drilling services performed for BP, ExxonMobil and PDVSA in ﬁscal 2005 accounted for approximately 11 percent, 9 percent and 8 percent, respectively, of the Company’s consolidated operating revenues for the same period. 1 The Company provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided so that the Company’s customers may explore for and develop oil and gas from onshore areas and from ﬁxed platforms, tension-leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drillstring, and related equipment. The intended well depth and the drilling site conditions are 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 “FlexRigT”). 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 $11.2 million 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. During ﬁscal 2005 and the ﬁrst quarter of ﬁscal 2006, the Company entered into separate drilling contracts with 12 exploration and production companies to build and operate a total of 50 new FlexRigs. Of the 50 FlexRigs, eight are FlexRig3s and 42 are FlexRig4s (described below). Each of the drilling contracts provides for a minimum ﬁxed contract term of at least three years, with drilling services to be performed on a daywork contract basis. The FlexRig3 construction cost is approximately $14 million each and the FlexRig4 cost is approximately $11 million each. While the Company experienced an approximate 30-day construction schedule delay due to Hurricanes Katrina and Rita, approximately 30 FlexRigs should be completed during ﬁscal 2006 and the remainder by the end of ﬁscal 2007. This 50 rig new-build project represents the single largest rig construction project in the Company’s history. While the new FlexRig3s are similar to the Company’s existing FlexRig3s, the FlexRig4s are designed to efﬁciently drill shallower depth wells of between 4,000 and 14,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate new environmental and safety design. This new design includes a pipe handling system which allows the rig to be operated by a reduced crew and eliminates the need for a casing stabber in the mast. While the trailerized version provides for more efﬁcient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which will result in reduced environmental impact. 2 The Company utilizes a lean manufacturing process in the construction of its FlexRigs. This approach minimizes the amount of equipment and supplies that must be inventoried. However, after experiencing delays resulting from Hurricanes Katrina and Rita, the Company will temporarily inventory increased amounts of equipment and supplies to reduce future delays. 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 2005, 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 2005. The Company believes that under current market conditions “footage” and “turnkey” contract rates do not adequately compensate contractors for the added risks. The duration of the Company’s drilling contracts are “well-to-well” or for a ﬁxed term. “Well-to-well” contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the contractor if a contract is terminated prior to the expiration of the ﬁxed term. However, under certain limited circumstances such as destruction of a drilling rig or sustained unacceptable performance, no early termination payment would be paid to the contractor. Excluding the ﬁxed term contracts covering the 50 FlexRig new-build project, the Company has 33 rigs under ﬁxed term contracts as of the end of November 2005. While the duration for these 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. U . S . L A N D D R I L L I N G At the end of September, 2005 and 2004, the Company had 91 and 87, 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 six rigs moving back from the Company’s international ﬂeet during ﬁscal year 2005, and the sale of two conventional rigs in November of 2004. The Company’s U.S. land operations contributed approximately 66 percent of the Company’s consolidated operating revenues during ﬁscal 2005, compared with approximately 59 percent of consolidated operating revenues during ﬁscal 2004 and approximately 54 percent of consolidated operating revenues during ﬁscal 2003. Rig utilization in ﬁscal 2005 was approximately 94 percent, up from approximately 87 percent in ﬁscal 2004. The Company’s ﬂeet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 99 percent during ﬁscal 2005 while the Company’s conventional rigs had an average utilization rate of approximately 82 percent. At the close of ﬁscal 2005, 87 land rigs were working out of 91 available rigs. 3 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 11 percent of the Company’s consolidated operating revenues during ﬁscal 2005, compared with approximately 14 percent of consolidated operating revenues during ﬁscal 2004 and approximately 22 percent of consolidated operating revenues during ﬁscal 2003. Rig utilization in ﬁscal 2005 was approximately 53 percent, up from approximately 48 percent in ﬁscal 2004. At the end of this ﬁscal year, the Company had seven of its 11 offshore platform rigs (excluding Rig 201) under contract and continued to work under management contracts for two customer-owned rigs. Revenues from drilling services performed for the Company’s largest offshore platform drilling customer totaled approximately 73 percent of U.S. offshore platform revenues during ﬁscal 2005. The Company’s offshore platform Rig 201 sustained signiﬁcant damage from Hurricane Katrina. Speciﬁc equipment damage assessment has not been completed. The Company does not anticipate Rig 201 returning to service during ﬁscal 2006. The rig was insured at a value that approximated replacement cost. Excluding Rig 201, seven platform rigs are under contract as of the end of November 2005, and one additional rig is expected to be contracted for work commencing the second ﬁscal quarter of 2006. 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 22 percent of the Company’s consolidated operating revenues during ﬁscal 2005, compared with approximately 25 percent of consolidated operating revenues during ﬁscal 2004 and approximately 22 percent of consolidated operating revenues during ﬁscal 2003. Rig utilization in ﬁscal 2005 was 77 percent, up from 54 percent in ﬁscal 2004. Venezuela Venezuelan operations continue to be a signiﬁcant part of the Company’s operations. During ﬁscal 2005, the Company moved a highly mobile rig to the United States, reducing the rig count to 12 in Venezuela. The Company worked for the Venezuelan state petroleum company, PDVSA, during ﬁscal 2005 and revenues from this work accounted for approximately 8 percent of the Company’s consolidated operating revenues during the ﬁscal year and approximately 38 percent of international operating revenues. Revenues generated from all Venezuelan drilling operations contributed approximately 8 percent of the Company’s consolidated operating revenues during 2005, compared with approximately 10 percent of consolidated operating revenues during ﬁscal 2004 and 6 percent of consolidated operating revenues during 2003. The Company had nine rigs working in Venezuela at the end of ﬁscal 2005. The Company’s rig utilization rate in Venezuela has increased from approximately 65 percent during ﬁscal 2004 to approximately 72 percent in ﬁscal 2005. The Company has contracted to return one idle rig back to work during the second quarter of ﬁscal 2006. At this time, the Company is unable to predict future ﬂuctuations in its utilization rates. 4 Ecuador At the end of ﬁscal 2005, the Company owned eight rigs in Ecuador. The Company’s utilization rate was approximately 97 percent during ﬁscal 2005, up from approximately 74 percent in ﬁscal 2004. Revenues generated by Ecuadorian drilling operations contributed approximately 8 percent of the Company’s consolidated operating revenues during ﬁscal 2005, as compared with approximately 7 percent of consolidated operating revenues during ﬁscal 2004 and approximately 10 percent of consolidated operating revenues during ﬁscal 2003. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 3 percent of consolidated operating revenues and approximately 13 percent of international operating revenues during ﬁscal 2005. The Ecuadorian drilling contracts are primarily with large international oil companies. Colombia During ﬁscal 2005, the Company owned two rigs in Colombia. The Company’s utilization rate in Colombia was approximately 87 percent during ﬁscal 2005, up from approximately 13 percent in ﬁscal 2004. The revenues generated by Colombian drilling operations contributed approximately 2 percent of the Company’s consolidated operating revenues in ﬁscal 2005, as compared with approximately 1 percent of consolidated operating revenues during ﬁscal 2004 and ﬁscal 2003. At the end of ﬁscal 2005, the Company was operating two rigs in Colombia. Other Locations In addition to its operations in Venezuela, Ecuador and Colombia, at the end of ﬁscal 2005, the Company owned two rigs in Bolivia, and two rigs in Argentina. During ﬁscal 2005, one rig was moved to the United States from Hungary. At the end of November 2005, two rigs were working in Argentina with an additional rig moving to Argentina from the United States. This rig is under contract and expected to begin work during the second quarter of ﬁscal 2006. One rig has moved from Bolivia to Chile and started drilling operations, and one rig is under contract in Bolivia. It is expected to begin work during the second quarter of ﬁscal 2006. During ﬁscal 2005, 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 completed a drilling consulting services contract in Russia. The Company continues to pursue opportunities 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 was approximately 91 percent in ﬁscal 2005 and ﬁscal 2004. At the end of the 2005 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. Nine 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 approximately 89 percent, which is up from approximately 82 percent one year ago. The increase in occupancy is due to the 5 addition of three new tenants. The Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses. Southpark is an undeveloped tract of land located in a high growth area of southeast Tulsa and is suitable for mixed commercial and light industrial use. At the end of ﬁscal 2005, 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. Occupancy increased to approximately 89 percent in 2005 from approximately 82 percent in ﬁscal 2004 due to the addition of two new tenants. 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 topographic survey and preliminary site engineering 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/warehouse space. Occupancy has increased from approximately 69 percent in 2004 to approximately 76 percent during ﬁscal 2005 due to the addition of three tenants. The Company also owns a 12-building complex, consisting of approximately 204,600 square feet of ofﬁce/warehouse 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 2005, occupancy has decreased from approximately 81 percent to approximately 69 percent due to the loss of one tenant. 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 2005, occupancy has decreased to approximately 56 percent from approximately 94 percent due to the loss of one large tenant. 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 2005, occupancy has increased from approximately 44 percent to approximately 63 percent with the addition of one new tenant. The Company’s offsite disaster recovery center occupies approximately 3,517 square feet of ofﬁce and computer equipment space in this property. During ﬁscal 2005, the Company completed the demolition and site reclamation of its former headquarters building. 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 income or loss by business segments may be found on pages 82 through 86 of the Company’s Annual Report. E M P L O Y E E S The Company had 3,615 employees within the United States (six of which were part-time employees) and 1,186 employees in international operations as of September 30, 2005. 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 88 of the Company’s Annual Report. 6 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 and Rig Construction 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. The Company’s new-build rig assembly facility is located near the Houston, Texas ship channel. Also, certain of the Company’s fabricators and other vendors are located in the Gulf Coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage. 7 3. Fixed Term Contract Risk Fixed term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the Company if a contract is terminated prior to the expiration of the ﬁxed term. However, under certain limited circumstances, such as destruction of a drilling rig or sustained unacceptable performance by the Company, no early termination payment would be paid to the Company. 4. Indemniﬁcation and Insurance Coverage The Company has insurance coverage for comprehensive general liability, public liability, automobile liability, worker’s compensation, employer’s liability, and property damage. Generally, deductibles range from $1 million or $2 million per occurrence, depending on whether a claim occurs inside or outside of the United States. The Company maintains certain other insurance coverages with $5 million deductibles. Insurance is purchased over these deductibles to limit the Company’s exposure to catastrophic events. In ﬁscal 2005, the Company obtained property insurance coverage for 85 percent of the aggregate estimated replacement cost of its land rigs in excess of a $1 million deductible. The Company self-insured the remaining 15 percent of such land rig value. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain signiﬁcant amounts of insurance to cover risks of underground reservoir damage; however, the Company is generally indemniﬁed under its drilling contracts from this risk. The Company retains a signiﬁcant portion of its expected losses under its worker’s compensation, general, and automobile liability programs. 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. The majority of the Company’s insurance coverage has been purchased through ﬁscal 2006. Multiple hurricanes in the Gulf of Mexico during August and September had a severe impact on the availability and price of the Company’s rig property insurance coverage for 2006. As a result, the Company was able to place only 85 percent of its rig property coverage excess of a $1 million per occurrence deductible. In addition, the Company could share in losses up to a maximum of $5 million should loss levels exceed a set percentage of excess property premium. No assurance can be given that all or a portion of the Company’s coverage will not be cancelled during ﬁscal 2006 or that insurance coverage will continue to be available at rates considered reasonable. 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. 5. Availability of Equipment and Supplies The contract drilling business is highly cyclical. During periods of increased demand for contract drilling services, delays in delivery and shortages of drilling equipment and supplies can occur. These risks are intensiﬁed during periods when the industry experiences signiﬁcant new drilling rig construction or refurbishment. 6. 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, 8 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. 7. 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 2005, approximately 22 percent of the Company’s consolidated operating revenues were generated from the international contract drilling business. Approximately 85 percent of the international operating revenues were from operations in South America and approximately 84 percent of South American operating revenues were from Venezuela and Ecuador. 8. Currency Risk General Contracts for work in foreign countries generally provide for payment in United States dollars, except for amounts required to meet local expenses. However, government owned petroleum companies are more frequently requesting that a greater proportion of these payments be made in local currencies. Based upon current information, the Company believes that exposure to potential losses from currency devaluation is minimal in Colombia, Ecuador, Bolivia, and Equatorial Guinea. In those countries, all receivables and payments are currently in U.S. dollars. Cash balances are kept at a minimum which assists in reducing exposure. Argentina In 2002, Argentina suffered a 60 percent 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 experienced minimal Argentine currency losses in ﬁscal 2005. 9 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 40 percent of the Company’s invoice billings are in U.S. dollars and 60 percent are in the local currency, the bolivar. The signiﬁcance of this arrangement is that even though the dollar-based invoices may be paid in bolivares, the Company, historically, has usually been able to convert the bolivares 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 bolivares 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 bolivares 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 a 12 percent devaluation of the bolivar during ﬁscal 2005, the Company experienced total devaluation losses of $0.6 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. While the Company is unable to predict future devaluation in Venezuela, if ﬁscal 2006 activity levels are similar to ﬁscal 2005, and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.6 million to $2.9 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. Were this agreement to end, the Company would again receive these payments in bolivares and thus increase bolivar cash balances and exposure to devaluation. On September 28, 2005, the Company made application with the Venezuelan government requesting the approval to convert bolivar cash balances to U.S. dollars. Upon approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit those dollars as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation. 9. Governmental Instability in Venezuela Venezuela has a history of governmental instability. In the event that extended labor strikes or turmoil occurs, 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. 10 10. 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 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. 11. Interest Rate Risk The Company has a $200 million intermediate-term unsecured debt obligation with staged maturities from August 2007 to August 2014, with varying ﬁxed interest rates for each maturity series. There was $200 million outstanding at September 30, 2005, 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 6.4 percent, after which it increases to 6.5 percent. The fair value of this debt at September 30, 2005 was approximately $215 million. At September 30, 2005, the Company had in place a committed unsecured line of credit totaling $50 million with no outstanding borrowings. The Company, as of September 30, 2005, had letters of credit totaling $14 million outstanding against such line of credit. The Company’s line of credit interest rate is based on LIBOR plus 87.5 to 112.5 basis points or prime minus 175 to 150 basis points based on the Company’s EBITDA to net debt ratio. As the Company draws on this line of credit, it is subject to the interest rates prevailing during the term at which the Company had outstanding borrowings. Interest rates could rise for various reasons in the future and increase the Company’s total interest expense, depending upon the amount borrowed against the credit line. 12. Equity Price Risk At September 30, 2005, the Company owned stocks in other publicly held companies with a total market value of $293.4 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 section 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 $15.9 million ($0.31 per diluted share) of net income in ﬁscal 2005. The Company currently owns 2,000,000 shares of Atwood. 13. Reliance on Small Number of Customers In ﬁscal 2005, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers and approximately 28 percent of its consolidated operating 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. 11 14. 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. 15. 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. 16. 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 expectations. 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, 2005: Location FLEXRIGS Texas Texas Texas Texas Texas Texas Texas Wyoming Wyoming Texas Texas Texas Texas Texas Texas Texas Texas Oklahoma Texas Texas Texas Rig Optimum Depth Rig Type Drawworks: Horsepower 164 165 166 167 168 169 178 179 180 181 182 183 184 185 186 187 188 189 210 211 212 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 12 SCR (FlexRig1) SCR (FlexRig1) 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) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location Texas Texas Colorado Texas Texas Texas Texas Texas Louisiana Oklahoma Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Texas Colorado Texas Colorado HIGHLY MOBILE RIGS Oklahoma Oklahoma Texas Wyoming Texas Texas Oklahoma Texas Texas Wyoming Texas Wyoming Rig 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240 241 140 158 156 159 141 142 143 145 155 146 147 154 Optimum Depth Rig Type Drawworks: Horsepower AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) Mechanical SCR Mechanical Mechanical Mechanical Mechanical Mechanical Mechanical 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 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 900 900 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,500 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 10,000 10,000 12,000 12,000 14,000 14,000 14,000 14,000 14,000 16,000 16,000 16,000 13 Location Rig Optimum Depth Rig Type Drawworks: Horsepower CONVENTIONAL RIGS Texas Oklahoma Texas Oklahoma Texas Texas Wyoming Texas Texas Louisiana Oklahoma Texas Oklahoma Oklahoma Oklahoma Texas Texas Texas Texas Texas Louisiana Oklahoma Texas Texas Louisiana Texas Louisiana Louisiana Texas* OFFSHORE PLATFORM RIGS Louisiana Gulf of Mexico Gulf of Mexico Gulf of Mexico Gulf of Mexico Louisiana Louisiana Gulf of Mexico Gulf of Mexico Gulf of Mexico Gulf of Mexico 110 96 118 119 120 171 172 122 162 79 80 89 92 94 98 173 97 99 137 149 72 73 125 134 136 157 161 163 139 91 203 205 206 100 105 106 107 201 202 204 * Rig moved to Argentina in November, 2005 SCR SCR SCR SCR SCR Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR Mechanical 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 700 1,000 1,200 1,200 1,200 1,000 1,000 1,700 1,500 2,000 1,500 1,500 1,500 1,500 1,500 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 12,000 16,000 16,000 16,000 16,000 16,000 16,000 16,000 18,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 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 14 The following table sets forth information with respect to the utilization of the Company’s U.S. land and offshore drilling rigs for the periods indicated: Years ended September 30, 2001 2002 2003 2004 2005 U.S. Land Rigs Number of rigs owned at end of period Average rig utilization rate during period(1) U.S. Offshore Platform Rigs Number of rigs owned at end of period Average rig utilization rate during period(1) 49 97% 10 98% 66 84% 12 83% 83 81% 12 51% 87 87% 11 48% 91 94% 11 53% (1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2005: Location Argentina Argentina Bolivia* Bolivia Colombia Colombia Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 175 177 123 151 133 152 22 23 132 176 121 117 138 190 148 160 113 115 116 127 128 129 135 150 174 153 * Rig moved to Chile in the ﬁrst quarter of ﬁscal 2006 Optimum Depth Rig Type Drawworks: Horsepower SCR SCR SCR SCR SCR SCR SCR (Heli Rig) SCR (Heli Rig) SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 3,000 3,000 2,100 3,000 3,000 3,000 1,700 1,500 1,500 1,500 1,700 2,500 2,500 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 30,000 30,000 26,000 30,000+ 30,000 30,000+ 18,000 18,000 18,000 18,000 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 30,000+ 15 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, 2001 2002 2003 2004 2005 Number of rigs owned at end of period Average rig utilization rate during period(1)(2) 37 56% 33 51% 32 39% 32 54% 26 77% (1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. (2) Does not include rigs returned to United States for major modiﬁcations and upgrades. 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 5 through 6 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 48 of the Company’s Annual Report under the caption, “Management’s Discussion & 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 A T 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. I T E M 4 A . 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, 56 Vice President and Chief Financial Ofﬁcer since 1988 Steven R. Mackey, 54 Vice President, Secretary and General Counsel Secretary since 1990; Vice President and General Counsel since 1988 W. H. Helmerich, III, 82 Chairman of the Board Director since 1949; Chairman of the Board since 1960 Hans Helmerich, 47 President and Chief Executive Ofﬁcer Director since 1987; President and Chief Executive Ofﬁcer since 1989 George S. Dotson, 64 Vice President Director since 1990; Vice President since 1977 and President and Chief Operating Ofﬁcer of Helmerich & Payne International Drilling Co. since 1977 16 Effective March 1, 2006, following the retirement of George S. Dotson, John W. Lindsay and M. Alan Orr will serve as Executive Vice Presidents for Helmerich & Payne International Drilling Co. Mr. Lindsay will become Executive Vice President, U.S. and International Operations, and Mr. Orr will serve as Executive Vice President, Engineering and Development. Mr. Lindsay, age 45, joined the Company in 1987 as a drilling engineer. He has since served in various positions including operations manager for the Company’s Mid-Continent region and division manager of U.S. Land Operations. In 1997, Mr. Lindsay was appointed to his present position of Vice President, U.S. Land Operations, for Helmerich & Payne International Drilling Co. Mr. Lindsay graduated in 1986 from the University of Tulsa, where he earned a Bachelor of Science degree in Petroleum Engineering. Mr. Orr, age 54, joined the Company in 1975 as a roughneck. In his 30-year career, Mr. Orr has held various supervisory positions in the Company’s domestic and international operations. In 1992, Mr. Orr was appointed to his present position as Vice President and Chief Engineer for Helmerich & Payne International Drilling Co. Mr. Orr graduated from the United States Military Academy at West Point in 1973, with a Bachelor of Science degree in General Engineering. 17 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 A N D I S S U E R P U R C H A S E S O F E Q U I T Y S E C U R I T I E 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 2004 High Low $28.37 $23.77 30.61 29.55 29.07 27.02 24.25 24.01 2005 High Low $34.16 $27.66 41.10 46.92 61.12 31.57 37.38 47.61 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 2004 $ .080 .080 .080 .0825 2005 $.0825 .0825 .0825 .0825 2004 2005 $4,011,879 $4,165,965 4,017,204 4,032,709 4,160,221 4,213,594 4,226,835 4,259,852 The Company paid a cash dividend of $0.0825 per share on December 1, 2005, to shareholders of record on November 15, 2005. Payment of future dividends will depend on earnings and other factors. As of December 5, 2005, there were 808 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, 2005. EQUITY COMPENSATION PLAN INFORMATION 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)) Plan Category Equity compensation plans (a) (b) approved by security holders(1) 3,244,073 Equity compensation plans not approved by security holders(2) Total — 3,244,073 $24.566 — $24.566 (c) 754,505 — 754,505 (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. 18 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 & Analysis of Results of Operations and Financial Condition contained on pages 32 through 56 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 Operating revenues Asset Impairment Charge Other* Income from continuing operations Income from continuing operations per common share: Basic Diluted Total assets Long-term debt 2001 2002 2003 2004 2005 (in thousands except per share amounts) $ 528,187 $ 523,418 $ 504,223 $ 589,056 $ 800,726 — 15,266 80,467 — 28,925 53,706 — 11,783 17,873 51,516 32,957 — 46,093 4,359 127,606 1.61 1.58 1.08 1.07 0.36 0.35 0.09 0.09 2.50 2.45 1,300,121 1,227,313 1,417,770 1,406,844 1,663,350 50,000 100,000 200,000 200,000 200,000 Cash dividends declared per common share 0.30 0.31 0.32 0.3225 0.33 * Other includes gain on sale of assets and investment securities, interest income and dividend income. 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 A T 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 32 through 56 of the Company’s Annual Report under the caption “Management’s Discussion & Analysis of Results of Operations and Financial Condition.” I T E M 7 A . 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 under the caption “Risk Factors” beginning on page 7 of this Report and 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 53-55 55 55-56 56 19 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 58 through 87 of the Company’s Annual Report. I T E M 9 . C H A N G E S I N A N D D I S A G R E E M E N T S W I T H A C C O U N T A N T S O N A C C O U N T I N G A N D F I N A N C I A L D I S C L O S U R E None. I T E M 9 A . C O N T R O L S A N D P R O C E D U R E S (a) Evaluation of Disclosure Controls and Procedures As of the end of the period covered by this Annual Report on Form 10-K, the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Ofﬁcer and Chief Financial Ofﬁcer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s Chief Executive Ofﬁcer and Chief Financial Ofﬁcer believe that: • the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it ﬁles or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods speciﬁed in the SEC’s rules and forms; and • the Company’s disclosure controls and procedures operate such that important information ﬂows to 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) Management’s Report of Internal Control over Financial Reporting Management of the Company is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting as deﬁned in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over ﬁnancial reporting is designed to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over ﬁnancial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reﬂect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the Board of Directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the ﬁnancial statements. Because of its inherent limitations, internal control over ﬁnancial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk 20 that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Management, with the participation of the Company’s Chief Executive Ofﬁcer and Chief Financial Ofﬁcer, conducted its evaluation of the effectiveness of internal controls over ﬁnancial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal controls over ﬁnancial reporting, based on the Company’s evaluation, management has concluded that the Company’s internal controls over ﬁnancial reporting were effective as of September 30, 2005. The Company’s registered public accounting ﬁrm that audited the Company’s ﬁnancial statements, Ernst & Young LLP, has issued a report on management’s assessment of the Company’s internal control over ﬁnancial reporting. This report appears below. 21 Report of Independent Registered Public Accounting Firm Board of Directors and Shareholders of Helmerich & Payne, Inc. We have audited management’s assessment, included in the accompanying Management’s Report of Internal Control over Financial Reporting, that Helmerich & Payne, Inc. maintained effective internal control over ﬁnancial reporting as of September 30, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich and Payne, Inc.’s management is responsible for maintaining effective internal control over ﬁnancial reporting and for its assessment of the effectiveness of internal control over ﬁnancial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over ﬁnancial reporting based on our audit. We conducted our audit 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 effective internal control over ﬁnancial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over ﬁnancial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over ﬁnancial reporting is a process designed to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over ﬁnancial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reﬂect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, 22 use, or disposition of the company’s assets that could have a material effect on the ﬁnancial statements. Because of its inherent limitations, internal control over ﬁnancial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management’s assessment that Helmerich & Payne, Inc. maintained effective internal control over ﬁnancial reporting as of September 30, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over ﬁnancial reporting as of September 30, 2005, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2005 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash ﬂows for each of the three years in the period ended September 30, 2005 and our report dated December 1, 2005, except for Note 15, as to which the date is December 7, 2005, expressed an unqualiﬁed opinion thereon. E R N S T & Y O U N G L L P Tulsa, Oklahoma December 1, 2005 (c) 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 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over ﬁnancial reporting. 23 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 1, 2006, to be ﬁled with the Commission not later than 120 days after September 30, 2005. The information required by this Item with respect to the Company’s Executive Ofﬁcers appears on pages 16 and 17 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 1, 2006, to be ﬁled with the Commission not later than 120 days after September 30, 2005. 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 1, 2006, to be ﬁled with the Commission not later than 120 days after September 30, 2005. 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 1, 2006, to be ﬁled with the Commission not later than 120 days after September 30, 2005. 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 1, 2006, to be ﬁled with the Commission not later than 120 days after September 30, 2005. 24 PART IV I T E M 1 5 . E X H I B I T S A N D F I N A N C I A L S T A T E M E N T S C H E D U L E S a) 1. Financial Statements: The following appear in the Company’s Annual Report on the pages indicated below and are incorporated herein by reference: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets at September 30, 2005 and 2004 Consolidated Statements of Income for the Years Ended September 30, 2005, 2004 and 2003 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2005, 2004 and 2003 Consolidated Statements of Cash Flows for the Years Ended September 30, 2005, 2004 and 2003 Notes to Consolidated Financial Statements 57 58 59- 60 61 62 63-87 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 Annual Report. Exhibits incorporated by reference or which are otherwise not included herein are available free of charge upon written request. 3.1 Restated Certiﬁcate of Incorporation and Amendment to Restated Certiﬁcate of Incorporation of the Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for ﬁscal 1996, SEC File No. 001-04221. 3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2002, SEC File No. 001-04221. 4.1 Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company’s Form 8-A, dated January 18, 1996, SEC File No. 001-04221. 4.2 Amendment No. 1 to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company’s Form 8-K ﬁled on December 12, 2005. *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. 25 *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 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, N.A. 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. 10.14 First Amendment to Credit Agreement dated July 15, 2003, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. 10.15 Second Amendment to Credit Agreement dated May 4, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. 10.16 Third Amendment to Credit Agreement dated July 13, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. 10.17 Fourth Amendment to Credit Agreement dated July 12, 2005, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K ﬁled on July 13, 2005, SEC File No. 001-04221. 10.18 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. 26 10.19 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. *10.20 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. 10.21 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. 10.22 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. *10.23 Amended and restated Helmerich & Payne, Inc. Annual Bonus Plan for Executive Ofﬁcers, together with ﬁscal 2005 Executive Ofﬁcer Compensation, is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K ﬁled on December 9, 2005. 13. The Company’s Annual Report to Shareholders for ﬁscal 2005. 21. List of Subsidiaries of the Company. 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. 27 28 C E R T I F I C A T I O N I, Hans Helmerich, President and Chief Executive Ofﬁcer of Helmerich & Payne, Inc. (the “Company”), certify that: 1. 2. 3. 4. I have reviewed this Report on Form 10-K of the Company; Based on my knowledge, this 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 report; Based on my knowledge, the ﬁnancial statements, and other ﬁnancial information included in this report, fairly present in all material respects the ﬁnancial condition, results of operations and cash ﬂows of the Company as of, and for, the periods presented in this report; The Company’s other certifying ofﬁcer 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)) and internal control over ﬁnancial reporting (as deﬁned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and we 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 Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over ﬁnancial reporting, or caused such internal control over ﬁnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; d) Disclosed in this report any change in the Company’s internal control over ﬁnancial reporting that occurred during the Company’s most recent ﬁscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over ﬁnancial reporting; and 5. The Company’s other certifying ofﬁcer and I have disclosed, based on our most recent evaluation of internal control over ﬁnancial reporting, to the Company’s auditors and the Audit Committee of the Company’s Board of Directors (or persons performing the equivalent function): 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 Company’s ability to record, process, summarize and report ﬁnancial data information; and b) Any fraud, whether or not material, that involves management or other employees who have a signiﬁcant role in the Company’s internal control over ﬁnancial reporting. Date: December 13, 2005 /s/ Hans Helmerich Hans Helmerich President and Chief Executive Ofﬁcer 29 C E R T I F I C A T I O N I, Douglas E. Fears, Vice President and Chief Financial Ofﬁcer of Helmerich & Payne, Inc. (the “Company”), certify that: 1. 2. 3. 4. I have reviewed this report on Form 10-K of the Company; Based on my knowledge, this 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 report; Based on my knowledge, the ﬁnancial statements, and other ﬁnancial information included in this report, fairly present in all material respects the ﬁnancial condition, results of operations and cash ﬂows of the Company as of, and for, the periods presented in this report; The Company’s other certifying ofﬁcer 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)) and internal control over ﬁnancial reporting (as deﬁned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and we 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 Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over ﬁnancial reporting, or caused such internal control over ﬁnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; d) Disclosed in this report any change in the Company’s internal control over ﬁnancial reporting that occurred during the Company’s most recent ﬁscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over ﬁnancial reporting; and 5. The Company’s other certifying ofﬁcer and I have disclosed, based on our most recent evaluation of internal control over ﬁnancial reporting, to the Company’s auditors and the Audit Committee of the Company’s Board of Directors (or persons performing the equivalent function): 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 Company’s ability to record, process, summarize and report ﬁnancial data information; and b) Any fraud, whether or not material, that involves management or other employees who have a signiﬁcant role in the Company’s internal control over ﬁnancial reporting. Date: December 13, 2005 /s/ Douglas E. Fears Douglas E. Fears Vice President and Chief Financial Ofﬁcer 30 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, 2005 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 Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended; 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, 2005 /s/ Douglas E. Fears Douglas E. Fears Chief Financial Ofﬁcer December 13, 2005 31 Management’s Discussion & Analysis of Results of Operations and Financial Condition R I S K F A C T O R S A N D F O R WA R D - L O O K I N G S TAT E M E N T S The following discussion should be read in conjunction with the consolidated ﬁnancial statements and related notes included elsewhere herein. The Company’s future operating results may be affected by various trends and factors, which are beyond the Company’s control. These include, among other factors, ﬂuctuations in oil and natural gas prices, expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, and uncertain business conditions that affect the Company’s businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends. With the exception of historical information, the matters discussed in Management’s Discussion & Analysis of Results of Operations and Financial Condition include forward-looking statements. These forward-looking statements are based on various assumptions. The Company cautions that, while it believes such assumptions to be reasonable and makes them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. The Company is including this cautionary statement to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. The factors identiﬁed in this cautionary statement and those factors discussed under Risk Factors beginning on page 7 of the Company’s Annual Report on Form 10-K 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. The Company undertakes no 32 duty to update or revise its forward-looking statements based on changes of internal estimates or expectations or otherwise. E X E C U T I V E S U M M A R Y Helmerich & Payne, Inc. is primarily a contract drilling company which owned and operated a total of 128 drilling rigs at September 30, 2005. The Company’s contract drilling business includes the U.S. land rig business in which the Company owned 91 rigs, the U.S. offshore platform rig business in which the Company owned 11 offshore platform rigs, and the international land rig business in which the Company owned 26 rigs at year end. Crude oil and natural gas prices have continued to rise due to the uncertainty of both commodities. The recent hurricanes in the Gulf of Mexico contributed to the instability of these markets because of a concern of a possible 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 in all segments. R E S U L T S O F O P E R A T 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 2005 was $127.6 million ($2.45 per share), compared with $4.4 million ($0.09 per share) for 2004 and $17.9 million ($0.35 per share) for 2003. Included in 2004 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). Included in the Company’s net income, but not related to its operations, were after-tax gains from the sale of investment securities of $16.4 million ($0.32 per share) in 2005, $14.1 million ($0.28 per share) in 2004, and $3.3 million ($0.07 per share) in 2003. In addition to income from security sales, the Company 33 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 $0.05 per share in 2005, $0.01 per share in 2004 and a loss of $0.03 per share in 2003. (See Liquidity section of MD&A for discussion of the sale of a portion of the Company’s Atwood Oceanic stock in October 2004.) Consolidated operating revenues were $800.7 million in 2005, $589.1 million in 2004, and $504.2 million in 2003. Over the three- year period, U.S. land revenues increased due to the addition of FlexRigs combined with signiﬁcant increases in dayrates. The average number of U.S. land rigs available was 90 rigs in 2005, 86 rigs in 2004 and 76 rigs in 2003. U.S. land rig utilizations for the Company were 94 percent in 2005, 87 percent in 2004 and 81 percent in 2003. Revenue in the offshore platform business remained steady in 2005 from 2004 after a decline in 2003. International rig revenues increased from 2003 to 2005, as rig utilizations improved from 39 percent in 2003, 54 percent in 2004 and 77 percent in 2005. Gains from the sale of investment securities were $27.0 million in 2005, $25.4 million in 2004, and $5.5 million in 2003. Interest and dividend income fell from $2.5 million in 2003 to $2.0 million in 2004 due to reduced cash positions, lower interest rates, and a reduction in the Company’s equity portfolio. In 2005, interest and dividend income increased to $5.8 million due to increased cash positions generated from the sale of equity securities, the sale of two U.S. land rigs and increased cash ﬂow. 34 Direct operating costs in 2005 were $484.2 million or 60 percent of operating revenues, compared with $417.7 million or 71 percent of operating revenues in 2004, and $346.3 million or 69 percent of operating revenues in 2003. The 2005 expense to revenue percentage decreased from 2004 and 2003 due to higher U.S. land revenue per day. Depreciation expense was $96.3 million in 2005, $94.4 million in 2004 and $82.5 million in 2003. Depreciation expense increased 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 2006 depreciation expense to increase from 2005 as the rigs currently under construction are placed into service. (See Liquidity and Capital Resources.) Yearly, management performs an analysis of the general industry market conditions in each drilling segment. Based on this analysis, management determines if an impairment is required. In 2005 and 2003, no impairment was recorded. In 2004, management determined that the carrying value of certain offshore rigs exceeded the estimated undiscounted future cash ﬂows associated with these assets. Accordingly, a pre-tax asset impairment charge of $51.5 million was recorded in the fourth quarter of ﬁscal 2004 to reduce the carrying value of the assets to their estimated fair value. The fair value of drilling rigs is determined based on quoted market prices, if available. Otherwise it is determined based upon estimated discounted future cash ﬂows and rig utilization. Cash ﬂows are 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 a rig marketable, suitability of rig size 35 and makeup to existing platforms, and new competitive dynamics due to lower industry utilization. General and administrative expenses totaled $41.0 million in 2005, $37.7 million in 2004, and $41.0 million for 2003. The increase from 2004 to 2005 was the result of increases in employee beneﬁts relating to medical insurance and 401(k) matching expenses, professional services associated with Sarbanes-Oxley and employee salaries and bonuses. 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. Interest expense was $12.6 million in 2005, $12.7 million in 2004 and $12.3 million in 2003. The interest expense in each year is primarily attributable to the $200 million of intermediate debt outstanding. Included in 2004 and 2003 is interest for short-term borrowings. Capitalized interest was $.3 million, $.5 million and $1.8 million in 2005, 2004 and 2003, respectively. The provision for income taxes totaled $87.5 million in 2005, $4.4 million in 2004, and $14.6 million in 2003. Effective income tax rates were 41 percent in 2005, 55 percent in 2004, and 43 percent in 2003. 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 income. International operating income, as a percent of the Company’s total 36 operating income, was 11 percent in 2005, 31 percent in 2004 (excluding the asset impairment charge from total operating income), and 14 percent in 2003. (See Note 4 of the Financial Statements for additional income tax disclosures.) C O M P A 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 5 A N D 2 0 0 4 U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Operating income 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 2005 2004 % Change (in thousands, except operating statistics) $527,637 294,164 8,594 60,222 $164,657 30,968 $ 15,941 $ 8,403 $ 7,538 91 94% $346,015 246,177 7,765 56,528 $ 35,545 27,472 $ 11,635 $ 8,001 $ 3,634 87 87% 52.5% 19.5 10.7 6.5 363.2 12.7% 37.0 5.0 107.4 4.6 8.0 Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. The Company’s U.S. land rig operating income increased to $164.7 million in 2005 from $35.5 million in 2004. During the fourth quarter of ﬁscal 2004, the Company began to experience an improvement in revenue and margin per day due to higher levels of U.S. land rig activity and higher dayrates. The improvement continued during 2005, as crude oil and natural gas prices remained at historical high levels. Rig utilization increased to 94 percent in 2005 from 87 percent in 2004. The increase in utilization is a result of higher rig activity. Average rig expense per day increased 5 percent as the energy industry experienced demands on both costs and labor. The total number of rigs available at September 30, 2005 was 91 compared 37 to 87 rigs at September 30, 2004. The increase is due to six rigs moving to U.S. land operations from the Company’s international ﬂeet during 2005 and the sale of two conventional rigs in November 2004. Depreciation in 2005 increased 6.5 percent from 2004 due to the increase in available rigs. During 2005 and subsequent to September 30, 2005, the Company announced plans to build 50 new FlexRigs. All of the new rigs will be operated by the Company under minimum ﬁxed contract term agreements with at least a three-year term. The drilling services will be performed on a daywork contract basis. The ﬁrst new FlexRig will be delivered to the ﬁeld in December 2005, and thereafter at a rate of two per month, with delivery expected to increase to four per month by the fourth quarter of ﬁscal 2006. As a result of the new FlexRigs, the Company anticipates depreciation expense to increase in ﬁscal 2006. 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 5 A N D 2 0 0 4 U.S. OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Asset impairment charge Operating income (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 2005 $84,921 52,786 3,825 10,602 — $17,708 2,122 $29,228 $15,967 $13,261 11 53% 2004 % Change (in thousands, except operating statistics) $ 84,238 52,987 3,256 12,107 51,516 $(35,628) 2,088 $ 29,070 $ 16,509 $ 12,561 11 48% .8% (.4) 17.5 (12.4) 149.7 1.6% .5 (3.3) 5.6 — 10.4 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. 38 Operating income in the Company’s U.S. offshore platform rig operations increased from a loss of $35.6 million in 2004, to income of $17.7 million in 2005. The loss in 2004 was due primarily to the asset impairment charge of $51.5 million. Excluding the asset impairment charge, operating income would have been $15.9 million for 2004. Lower depreciation expense in 2005 was a result of the asset impairment. Operating income (loss), as reported Asset impairment charge Operating income, excluding asset impairment charge 2005 $17.7 — $17.7 2004 % Change (in millions) (35.6) 51.5 15.9 11.5% Note: This table is a reconciliation of operating income (loss) for the offshore platform segment for ﬁscal 2005 and 2004, which is provided to assist with yearly comparisons. Operating income in the Company’s U.S. offshore operations, excluding the asset impairment charge in ﬁscal 2004, increased 11.5 percent in 2005 from 2004. On September 30, 2004, one of the Company’s older rigs was written down to its salvage value and removed from the active rig count. As a result, rig utilization increased to 53 percent in 2005, from 48 percent in 2004. During the fourth quarter of ﬁscal 2005, the Company’s Rig 201 was damaged by Hurricane Katrina. Fiscal 2005 operating income was negatively impacted by approximately $.6 million due to the rig being removed from service during the fourth quarter. The Company does not anticipate Rig 201 returning to work during ﬁscal 2006. The rig was insured at a value that approximated replacement cost and therefore the Company expects to record a gain resulting from the receipt of insurance proceeds. Because the damage assessment has not been completed, the Company is unable to estimate the amount or timing of the gain. 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 5 A N D 2 0 0 4 INTERNATIONAL OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Operating income 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 2005 2004 % Change (in thousands, except operating statistics) $177,480 135,837 2,563 20,107 $ 18,973 7,491 $ 19,332 $ 14,039 $ 5,293 26 77% $148,788 113,988 2,144 20,530 $ 12,126 6,266 $ 19,580 $ 14,279 $ 5,301 32 54% 19.3% 19.2 19.5 (2.1) 56.5 19.5% (1.3) (1.7) (.2) (18.8) 42.6 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. Operating income for the Company’s international operations increased 56.5 percent from 2004 to 2005 due to higher rig activity. Rig utilization for international operations averaged 77 percent in 2005, compared with 54 percent in 2004. Operations in Colombia and Ecuador improved due to increased demand in these countries. Two deep rigs worked in Colombia at 87 percent activity during 2005, compared to 13 percent activity during the previous year. Ecuador’s rig utilization was 97 percent for 2005, with an average of 7.8 rigs worked during 2005, compared with 74 percent and an average of 5.9 rigs worked in 2004. Despite the increase in operating income and rig activity, rig margins for international operations decreased slightly in 2005. The decrease is attributable to higher labor costs, including a fourth quarter expense due to the Company not having an adequate reserve for government stipulated deferred compensation payments to Venezuela rig employees. 40 In Venezuela, the Company had nine deep rigs working for PDVSA at the end of ﬁscal 2005. One additional rig is under contract and will begin operations in the second quarter of ﬁscal 2006. Two rigs remain idle in Venezuela. Ecuador and Colombia remain at 100% rig utilization. Argentina currently has two rigs working and a third rig is relocating to Northern Argentina from the U.S. land operations and is expected to begin work during the second quarter of ﬁscal 2006. Chile began operations in the ﬁrst quarter of ﬁscal 2006. Bolivia has one rig contracted and is expected to begin work during the second quarter of ﬁscal 2006. Operations in Hungary ceased in 2005. 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 5 A N D 2 0 0 4 REAL ESTATE Operating revenues Direct operating expenses Depreciation Operating income 2005 $10,688 3,622 2,352 $ 4,714 2004 % Change (in thousands) $10,015 4,564 2,253 $ 3,198 6.7% (20.6) 4.4 47.4 Operating income in the Company’s Real Estate division increased 47.4 percent from 2004 to 2005. Direct operating expenses decreased in 2005 from 2004 due to reduced building expenses and lower demolition costs relating to the razing of the Company’s former headquarters building, which started in 2004, and was completed in 2005. 41 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 Operating revenues Direct operating expenses General and administrative expense Depreciation Operating income 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) $346,015 246,177 7,765 56,528 $ 35,545 27,472 $ 11,635 $ 8,001 $ 3,634 87 87% $273,179 201,398 9,304 44,726 $ 17,751 22,588 $ 11,400 $ 8,222 $ 3,178 83 81% 26.7% 22.2 (16.5) 26.4 100.2 21.6% 2.1 (2.7) 14.3 4.8 7.4 Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses. The Company’s operating income in its U.S. land rig operations increased by 100.2 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 margin per 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 ﬁscal 2004, the Company began to experience a more signiﬁcant improvement in revenue and margin per day due to higher levels of U.S. land rig activity. The 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 42 in service during 2003, total U.S. land rig depreciation increased 26.4 percent from 2003 to 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 U.S. OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Asset impairment charge Operating income (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 % Change (in thousands, except operating statistics) $ 84,238 52,987 3,256 12,107 51,516 $(35,628) 2,088 $ 29,070 $ 16,509 $ 12,561 11 48% $112,259 60,589 2,939 12,799 — $ 35,932 2,233 $ 38,076 $ 17,823 $ 20,253 12 51% (25.0)% (12.5) 10.8 (5.4) (199.2) (6.5) (23.7) (7.4) (38.0) (8.3) (5.9) 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. Operating income in the Company’s U.S. offshore platform rig operations fell from $35.9 million during 2003 to a loss of $35.6 million in 2004 due primarily to the asset impairment charge of $51.5 million. Excluding the asset impairment charge, operating income would have been $15.9 million for 2004 which is a $20.0 million decline from 2003. 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 operating revenues and revenue per day declined due to changes in the nature of contract terms on several of the Company’s rigs. During 2003, 43 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 ﬁscal 2003 were changed to standby status, thereby reducing total operating revenues and proﬁtability. These speciﬁc transactions, coupled with an overall softening in the market, caused average rig revenue and margin per 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 Operating revenues Direct operating expenses General and administrative expense Depreciation Operating income 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) $148,788 113,988 2,144 20,530 $ 12,126 6,266 $ 19,580 $ 14,279 $ 5,301 32 54% $109,517 81,461 3,110 20,092 $ 4,854 4,515 $ 19,538 $ 14,140 $ 5,398 32 39% 35.9% 39.9 (31.1) 2.2 149.8 38.8% .2 1.0 (1.8) — 38.5 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. Operating income for the Company’s international operations increased 149.8 percent from 2003 to 2004 due to higher rig activity and lower general and administrative expense resulting from reduced salary, bonus and travel expense. Rig activity improved primarily due to increased 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 44 improve overall production rates following the reduction in production caused by 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.) 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 Operating revenues Direct operating expenses Depreciation Operating income 2004 $10,015 4,564 2,253 $ 3,198 2003 % Change (in thousands) $9,268 2,811 2,535 $3,922 8.1% 62.4 (11.1) (18.5) Operating income decreased by 18.5 percent from 2003 to 2004 in the Company’s Real Estate division. Direct operating expenses increased in 2004 due to demolition costs of over $.8 million relating to the razing of the Company’s former headquarters building and an increase in advertising expense. Depreciation in 2003 was higher than 2004 due to the acceleration of depreciation on the razed building. 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 operations was $86.8 million in 2005, $90.2 million in 2004, and $242.9 million in 2003. Net cash provided from operating activities for those same time periods was $212.2 million in 2005, $136.6 million in 2004 and $93.1 million in 2003. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $46.7 million in 2005, $30.9 million in 2004, and $18.2 million in 2003. The Company’s 2006 capital spending 45 estimate is approximately $500 million, an increase from the budgeted $95 million in 2005, due to the construction of new FlexRigs. During 2003, 19 rigs from the FlexRig3 program were completed and another ﬁve were completed by March, 2004. During 2005 and subsequent to September 30, 2005, the Company announced contracts to operate eight new FlexRig3s and 42 new FlexRig4s for 12 exploration and production companies. The ﬁrst rig is scheduled for completion in December 2005, with the remaining rigs expected to be delivered at a rate of two per month, with delivery expected to increase to four per month by the fourth quarter of ﬁscal 2006. Projected rig construction is expected to average approximately $11.0 million to $14.0 million per rig depending on equipment requirements. Each agreement has at least a three-year commitment by the operator under a minimum ﬁxed contract. The drilling services will be performed on a daywork contract basis. Current cash, investments in short-term money market securities, and projected cash generated from operating activities are anticipated to meet the Company’s current estimated capital expenditures and other expected cash requirements for ﬁscal 2006. The Company has $200 million intermediate-term unsecured debt obligations with staged maturities from August, 2007 to August, 2014. The annual average interest rate through maturity will be 6.43 percent. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. On September 30, 2005, the Company had a committed unsecured line of credit totaling $50 million, with no money drawn and letters 46 of credit totaling $14 million outstanding against the line. The line of credit matures in 2006 and bears interest of LIBOR plus .875 percent to 1.125 percent or prime minus 1.75 percent to prime minus 1.50 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 a certain level of tangible net worth. Current ratios for September 30, 2005 and 2004 were 5.6 and 4.1, respectively. The debt to total capitalization ratio was 16 percent and 18 percent at September 30, 2005 and 2004, respectively. Additionally, the Company manages a portfolio of marketable securities that, at the close of 2005, had a market value of $293.4 million. The Company’s investments in Atwood Oceanics, Inc., and Schlumberger, Ltd., made up almost 93 percent of the portfolio’s market value on September 30, 2005. 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 Helmerich & Payne. On October 19, 2004, Atwood and Helmerich & Payne closed a public offering in which Helmerich & Payne sold 1,000,000 Atwood shares and received $45.6 million. The Company now owns 2,000,000 shares or approximately 13.0 percent of the outstanding shares of Atwood. 47 During 2005, the Company paid a dividend of $0.33 per share, or a total of $16.9 million, representing the 33rd 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, 2005 Number of Shares Cost Basis Market Value Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total (in thousands, except share amounts) 2,000,000 1,230,000 $46,533 19,539 11,398 $77,470 $168,420 103,787 21,150 $293,357 M A T E R I A L C O M M I T M E N T S The Company has no off balance sheet arrangements other than operating leases. The Company’s contractual obligations as of September 30, 2005, are summarized in the table below: Payments Due By Year Total 2006 2007 2008 2009 2010 After 2010 Long-term debt (a) Operating leases (b) $200,000 9,231 Total Contractual Obligations $209,231 $ — 3,095 $3,095 $25,000 2,470 $27,470 $ — 1,615 $1,615 $25,000 1,569 $26,569 $ — 482 $482 $150,000 — $150,000 (in thousands) (a) See Note 3 “Notes Payable and Long-Term Debt” to the Company’s Consolidated Financial Statements. (b) See Note 13 “Contingent Liabilities and Commitments” 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, 2005 is $27.1 million. Based on current information available from plan actuaries, the Company anticipates contributions of approximately $2.8 million will be made in 2006. Future contributions beyond 2006 are difﬁcult to estimate due to multiple variables involved. 48 At September 30, 2005, the Company had commitments outstanding of approximately $96.2 million for the purchase of contract drilling equipment. 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 A N D E S T I M AT 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. On an on-going basis, the Company evaluates the estimates, including those related to inventories, long-lived assets, and accrued insurance losses. The estimates are based on historical experience and on various other assumptions that the Company believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. 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 49 the respective accounts and any gains or losses are recorded in net income. 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 day, declining cash margin per 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 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 range from $1.0 million or $2.0 million per occurrence depending on whether a claim occurs inside or outside of the United States. Insurance is also purchased on rig properties and generally deductibles are $1.0 million per occurrence. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred, and using 50 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 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 in future periods. Revenues and costs on daywork contracts are recognized daily as the work progresses. For certain contracts, lump-sum payments are received for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to speciﬁc contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling 51 equipment to areas in which a contract has not been secured are expensed as incurred. N E W A C C O U N T I N G S TA N D A R D In December, 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), “Share-Based Payment”, which is a revision of FASB Statement No. 123, “Accounting for Stock-Based Compensation”. Statement 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” and amends FASB Statement No. 95, “Statement of Cash Flows”. The statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the ﬁnancial statements based on their fair value. The statement is effective at the beginning of the ﬁrst interim or annual period beginning after June 15, 2005, with the SEC allowing for implementation at the beginning of the ﬁrst ﬁscal year beginning after June 15, 2005. The Company plans to adopt the new standard the ﬁrst quarter of ﬁscal 2006, beginning October 1, 2005, under the modiﬁed-prospective- transition method. The Company will recognize compensation cost for share-based payments to employees based on their grant-date fair value from the beginning of the ﬁscal period in which the recognition provisions are ﬁrst applied. Measurement and attribution of compensation cost for awards that were granted but not vested prior to the date the Company adopts the new standard will be based on the same estimate of the grant-date fair value and the same attribution method used previously under Statement 123 for pro forma disclosure. For those awards that are granted, modiﬁed or settled after the Company adopts the Statement, compensation cost will be measured and recognized in the ﬁnancial statements in accordance with the provision of Statement 123(R). The Company expects to 52 incur additional pre-tax compensation expense of approximately $1.3 million related to options currently outstanding in the ﬁrst quarter of ﬁscal 2006 as a result of adopting Statement 123(R). Statement 123(R) also requires that the beneﬁts of tax deductions in excess of recognized compensation cost be reported as a ﬁnancing cash ﬂow, rather than an operating cash ﬂow as required under current literature. This requirement will reduce net operating cash ﬂows and increase net ﬁnancing cash ﬂows in periods after the effective date. The Company cannot estimate what those amounts will be in the future because they depend on, among other things, when employees exercise stock options. Q UA N T I TAT I V E A N D Q UA L I TAT I V E D I S C L O S U R E S A B O U T M A R K E T R I S K Foreign Currency Exchange Rate Risk The Company has international operations in several South American countries, as well as a labor contract for work in Equatorial Guinea. With the exception of Venezuela, the Company’s exposure to currency valuation losses is usually minimal due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars. 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 40 percent of the Company’s invoice billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 60 percent are in the local currency, the bolivar. 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 53 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. 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. The exchange rate increased to 2150 bolivares during 2005 from 1920 bolivares at September 30, 2004. As a result of the 12 percent devaluation of the bolivar during ﬁscal 2005 (from September 2004 through August 2005), the Company experienced total devaluation losses of $.6 million during that same period. This 12 percent devaluation loss may not be reﬂective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if ﬁscal 2006 activity levels are similar to ﬁscal 2005 and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.6 million to $2.9 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. 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 bolivares and thus increase bolivar cash balances and exposure to devaluation. On September 28, 2005, the Company made application with the Venezuelan government requesting the approval to convert bolivar cash balances to U.S. dollars. Upon approval from the Venezuelan 54 government, the Company’s Venezuelan subsidiary will remit those dollars as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency 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 on, among other things, crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile and very difﬁcult to predict. This difﬁculty has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services 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. 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, 2005 and 2004 about the Company’s interest rate risk sensitive instruments: 55 I N T E R E S T R AT E R I S K A S O F S E P T E M B E R 3 0 , 2 0 0 5 (in thousands) 2006 2007 2008 2009 2010 After 2010 Total Fair Value @ 9/30/05 Fixed Rate Debt — $25,000 — $25,000 — $150,000 $200,000 $215,000 Average Interest Rate — 5.5% — 5.9% — 6.5% 6.4% I N T E R E S T R AT E R I S K A S O F S E P T E M B E R 3 0 , 2 0 0 4 (in thousands) 2005 2006 2007 2008 2009 After 2009 Total Fair Value @ 9/30/04 Fixed Rate Debt Average Interest Rate — — — $25,000 — $25,000 $150,000 $200,000 $216,400 — 5.5% — 5.9% 6.5% 6.3% Equity Price Risk On September 30, 2005, the Company owned stocks in other publicly held companies with a total market value of $293.4 million. The Company’s investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up almost 93 percent of the portfolio’s market value at September 30, 2005. Although the Company sold portions of its positions in Schlumberger in 2004 and Atwood in the ﬁrst quarter of ﬁscal 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 $240.7 million at September 30, 2004. 56 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, 2005 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash ﬂows for each of the three years in the period ended September 30, 2005. 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, 2005 and 2004, and the consolidated results of its operations and its cash ﬂows for each of the three years in the period ended September 30, 2005, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Helmerich & Payne Inc.’s internal control over ﬁnancial reporting as of September 30, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 1, 2005 expressed an unqualiﬁed opinion thereon. E R N S T & Y O U N G L L P Tulsa, Oklahoma December 1, 2005 except for Note 15, as to which the date is December 7, 2005 57 Consolidated Balance Sheets ASSETS CURRENT ASSETS: September 30, 2005 2004 (in thousands) Cash and cash equivalents $ 288,752 $ 65,296 Accounts receivable, less reserve of $1,791 in 2005 and $1,265 in 2004 Inventories Deferred income taxes Prepaid expenses and other Total current assets 162,646 21,313 8,765 18,321 499,797 133,262 20,826 4,346 21,600 245,330 INVESTMENTS 178,452 161,532 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. 1,549,112 1,531,937 34,774 57,489 96,614 1,228 56,307 93,640 1,737,989 1,683,112 756,024 981,965 684,438 998,674 3,136 1,308 $1,663,350 $1,406,844 58 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, 2005 2004 (in thousands, except share data) CURRENT LIABILITIES: Accounts payable Accrued liabilities Total current liabilities NONCURRENT LIABILITIES: Long-term notes payable Deferred income taxes Other Total noncurrent liabilities SHAREHOLDERS’ EQUITY: Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Unearned compensation Accumulated other comprehensive income Less treasury stock, 1,594,362 shares in 2005 and 3,083,516 shares in 2004, at cost Total shareholders’ equity $ 44,854 $ 28,012 44,627 89,481 31,891 59,903 200,000 246,975 47,656 494,631 200,000 194,573 38,258 432,831 5,353 5,353 — 112,297 939,380 (134) 47,544 1,104,440 25,202 1,079,238 — 85,466 828,763 — 36,252 955,834 41,724 914,110 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $1,663,350 $1,406,844 The accompanying notes are an integral part of these statements. 59 Consolidated Statements of Income Years Ended September 30, 2005 2004 2003 OPERATING REVENUES Drilling – U.S. Land Drilling – U.S. Offshore Drilling – International Real Estate OPERATING COSTS AND EXPENSES Operating costs Depreciation Asset impairment General and administrative Operating income (loss) Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Income from asset sales Other (in thousands, except per share amounts) $527,637 $346,015 $273,179 84,921 177,480 10,688 800,726 484,231 96,274 — 41,015 621,520 84,238 148,788 10,015 589,056 417,716 94,425 51,516 37,661 601,318 112,259 109,517 9,268 504,223 346,259 82,513 — 41,003 469,775 179,206 (12,262) 34,448 5,809 (12,642) 26,969 13,550 (235) 33,451 1,965 (12,695) 25,418 5,377 197 20,262 8,000 4,365 724 2,467 (12,289) 5,529 3,689 98 (506) 33,942 14,649 (1,420) Income before income taxes and equity in income (loss) of afﬁliates 212,657 Income tax provision Equity in income (loss) of afﬁliates net of income taxes 87,463 2,412 NET INCOME Earnings per common share: Basic Diluted Average common shares outstanding (in thousands): Basic Diluted The accompanying notes are an integral part of these statements. $127,606 $ 4,359 $ 17,873 $ $ 2.50 2.45 $ $ 0.09 0.09 $ $ 0.36 0.35 51,087 52,033 50,312 50,833 50,039 50,596 60 Consolidated Statements of Shareholders’ Equity Common Stock Shares Amount Additional Paid-in Capital Retained Earnings Unearned Compensation Accumulated Other Comprehensive Income (Loss) Treasury Stock Shares Amount Total Balance, September 30, 2002 53,529 $5,353 $ 82,489 (in thousands, except per share amounts) $16,180 $(190) $838,929 3,518 $(47,591) $ 895,170 Comprehensive Income: Net Income Other comprehensive income: Unrealized gains on available- for-sale securities, net Derivatives instruments Amortization, net Minimum pension liability adjustment, net 17,873 15,005 982 1,501 (16,026) 441 372 (129) 1,753 53,529 5,353 83,302 840,776 180 (10) 33,668 3,389 (45,838) 4,359 3,721 72 (1,209) Total other comprehensive gain Total comprehensive income Cash dividends ($.3225 per share) Exercise of stock options Tax beneﬁt of stock-based awards Amortization of deferred compensation Balance, September 30, 2004 (16,372) 813 1,351 (305) 4,114 53,529 5,353 85,466 828,763 10 — 36,252 3,084 (41,724) Total other comprehensive gain Total comprehensive income Cash dividends ($.32 per share) Exercise of stock options Tax beneﬁt of stock-based awards Amortization of deferred compensation Balance, September 30, 2003 Comprehensive Income: Net Income Other comprehensive income (loss): Unrealized gains on available- for-sale securities, net Derivatives instruments Amortization, net Minimum pension liability adjustment, net Comprehensive Income: Net Income Other comprehensive income (loss): Unrealized gains on available-for- sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Capital adjustment of equity investee Stock issued under Restricted Stock Award Plan Cash dividends ($.33 per share) Exercise of stock options Tax beneﬁt of stock-based awards Amortization of deferred compensation Balance, September 30, 2005 127,606 2,682 93 8,903 15,153 (16,989) 14,708 (3,416) (160) 26 $(134) (5) (1,485) $47,544 1,594 67 16,455 — (16,989) 25,358 15,153 26 $(25,202) $1,079,238 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 10 914,110 127,606 14,708 (3,416) 11,292 138,898 2,682 The accompanying notes are an integral part of these statements. 61 53,529 $5,353 $112,297 $939,380 Consolidated Statements of Cash Flows Years Ended September 30, OPERATING ACTIVITIES: Net income Adjustments to reconcile income 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 sale of investment securities Non-monetary investment gain Gain on sale of assets 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 asset sales Purchase of investments Proceeds from sale of investments Net cash provided by (used in) investing activities FINANCING ACTIVITIES: Proceeds from 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 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. 2005 2004 (in thousands) 2003 $127,606 $ 4,359 $ 17,873 96,274 — (3,891) 26 (26,969) — (13,550) 38,014 (349) (46,223) (487) 1,451 8,517 12,736 16,557 2,526 84,632 212,238 (86,805) 28,992 (5,000) 65,539 2,726 — — (16,866) 25,358 8,492 223,456 65,296 94,425 51,516 (1,168) 10 (22,766) (2,521) (5,377) 5,934 (98) (25,335) 1,707 24,142 (378) 2,870 2,323 6,997 132,281 136,640 (90,212) 7,941 — 14,033 (68,238) — (30,000) (16,222) 4,927 (41,295) 27,107 38,189 82,513 — 2,290 180 (5,529) — (3,689) 41,391 336 1,516 251 (29,355) (14,804) (1,281) (166) 1,589 75,242 93,115 (242,912) 6,720 — 18,215 (217,977) 100,000 30,000 (16,026) 2,194 116,168 (8,694) 46,883 $288,752 $ 65,296 $ 38,189 62 Notes to Consolidated Financial Statements NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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. There were no signiﬁcant intervening events which materially affected the ﬁnancial statements. BASIS OF PRESENTATION 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 gains (losses) were $(.8) million, $(2.2) million and $.4 million for 2005, 2004, and 2003, respectively. These amounts are included in direct operating costs. USE OF ESTIMATES The preparation of ﬁnancial statements in conformity with U.S. 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 based on the average interest rate on related debt. Capitalized interest for 2005, 2004, and 2003 was $.3 million, $.5 million, and $1.8 million, respectively. 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 equal to the excess of the carrying value over the estimated fair value of long-lived assets used in 63 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. RESTRICTED CASH AND CASH EQUIVALENTS The Company had restricted cash and cash equivalents of $4.2 million and $2.0 million at September 30, 2005 and 2004, respectively. All restricted cash is for the purpose of potential insurance claims in the Company’s wholly-owned captive insurance company. Of the total, $2.0 million is from the initial capitalization of the captive and management has elected to restrict an additional $2.2 million. The restricted amounts are primarily invested in short-term money market securities. The restricted cash and cash equivalents is reﬂected in the balance sheet as follows (in thousands): September 30, Other current assets Other assets 2005 $2,195 $2,000 2004 $2,000 $ — INVENTORIES AND SUPPLIES Inventories and supplies are primarily replacement parts and supplies held for use in the Company’s 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. Reimbursements received by the Company for out-of-pocket expenses are recorded as revenues and 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 eleven 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. Recoveries from tenants for property taxes and operating expenses are recognized as Real Estate revenues in the Consolidated Statements of Income. The Company’s rent revenues are as follows: 64 Years Ended September 30, Minimum rents Overage and percentage rents 2005 $7,606 $1,162 2004 (in thousands) $7,490 $1,207 2003 $7,333 $ 768 At September 30, 2005, minimum future rental income to be received on noncancelable operating leases were as follows (in thousands): Fiscal Year 2006 2007 2008 2009 2010 Thereafter Total Amount $ 6,887 6,134 4,840 3,532 2,901 4,765 $29,059 Leasehold improvement allowances are capitalized and amortized over the lease term. INVESTMENTS The Company maintains investments in equity securities of unafﬁliated companies. 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. The Company regularly reviews investment securities for impairment based on criteria that include the extent to which the investment’s carrying value exceeds its related market value, the duration of the market decline and the ﬁnancial strength and speciﬁc prospects of the issuer of the security. Unrealized losses that are other than temporary are recognized in earnings. 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 September 30, 2004. 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 $15.9 million ($0.31 per diluted share) of net income in ﬁscal 2005. As a result of Atwood’s capital transaction, the Company’s equity investment increased by $4.3 million, deferred income taxes payable increased $1.6 million and additional paid-in-capital increased $2.7 million. With its remaining 2,000,000 shares of Atwood, the Company owns approximately 13.0 percent of Atwood. The Company 65 continues to account for Atwood on the equity method as the Company continues to have signiﬁcant inﬂuence through its board of director seats. The quoted market value of the Company’s investment was $168.4 million and $142.6 million at September 30, 2005 and 2004, respectively. Retained earnings at September 30, 2005 and 2004 includes approximately $24.3 million and $29.0 million, respectively of undistributed earnings of Atwood. Summarized ﬁnancial information of Atwood is as follows: September 30, Gross revenues Costs and expenses Net income (loss) 2005 $176,156 149,785 $ 26,371 2004 (in thousands) $163,454 155,867 $ 7,587 2003 $144,766 157,568 $ (12,802) Helmerich & Payne, Inc.’s equity in net income (loss), net of income taxes $ 2,412 $ 724 $ (1,414) Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity $ 93,283 $ 92,966 $ 76,012 403,641 56,159 78,268 362,497 405,970 60,053 167,294 271,589 446,662 49,949 209,258 263,467 Helmerich & Payne, Inc.’s investment $ 46,533 $ 57,824 $ 56,655 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. POST EMPLOYMENT AND OTHER 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. 66 EMPLOYEE STOCK-BASED AWARDS Employee stock-based awards are currently 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 5. The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”. September 30, 2005 2004 2003 (in thousands, except per share amounts) Net income, as reported $127,606 $ 4,359 $17,873 Stock-based employee compensation expense included in the Consolidated Statements of Income, net of related tax effects Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma net income Earnings per share: Basic-as reported Basic-pro forma Diluted-as reported Diluted-pro forma 16 6 112 (3,563) $124,059 $ $ $ $ 2.50 2.43 2.45 2.34 (4,172) $ 193 $ 0.09 $ 0.00 $ 0.09 $ 0.00 (4,387) $13,598 $ 0.36 $ 0.27 $ 0.35 $ 0.27 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. NEW ACCOUNTING STANDARD In December, 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), “Share-Based Payment”, which is a revision of FASB Statement No. 123, “Accounting for Stock-Based Compensation”. Statement 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” and amends FASB Statement No. 95, “Statement of Cash Flows”. The statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the ﬁnancial statements based on their fair value. The statement is effective at the beginning of the ﬁrst interim or annual period beginning after June 15, 2005, with the SEC allowing for implementation at the beginning of the 67 ﬁrst ﬁscal year beginning after June 15, 2005. The Company plans to adopt the new standard the ﬁrst quarter of ﬁscal 2006, beginning October 1, 2005, under the modiﬁed-prospective-transition method. The Company will recognize compensation cost for share-based payments to employees based on their grant-date fair value from the beginning of the ﬁscal period in which the recognition provisions are ﬁrst applied. Measurement and attribution of compensation cost for awards that were granted but not vested prior to the date the Company adopts the new standard will be based on the same estimate of the grant-date fair value and the same attribution method used previously under Statement 123 for pro forma disclosure. For those awards that are granted, modiﬁed or settled after the Company adopts the Statement, compensation cost will be measured and recognized in the ﬁnancial statements in accordance with the provision of Statement 123(R). The Company expects to incur additional pre-tax compensation expense of approximately $1.3 million related to options currently outstanding in the ﬁrst quarter of ﬁscal 2006 as a result of adopting Statement 123(R). Statement 123(R) also requires that the beneﬁts of tax deductions in excess of recognized compensation cost be reported as a ﬁnancing cash ﬂow, rather than an operating cash ﬂow as required under current literature. This requirement will reduce net operating cash ﬂows and increase net ﬁnancing cash ﬂows in periods after the effective date. The Company cannot estimate what those amounts will be in the future because they depend on, among other things, when employees exercise stock options. NOTE 2 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. 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 brought 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 the Offshore Platform segment was reduced by approximately $1.5 million in ﬁscal year 2005. 68 NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 2005, the Company had $200 million in unsecured long-term debt outstanding at ﬁxed rates and maturities as summarized in the following table. Issue Amount $25,000 $25,000 $75,000 $75,000 Maturity Date August 15, 2007 August 15, 2009 August 15, 2012 August 15, 2014 Interest Rate 5.51% 5.91% 6.46% 6.56% The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. The debt is held by various entities, including $8 million held by a company afﬁliated with one of the Company’s Board members. At September 30, 2005, the Company had a committed unsecured line of credit totaling $50 million. Letters of credit totaling $14 million were outstanding against the line, leaving $36 million available to borrow. Under terms of the line of credit, the Company must maintain certain ﬁnancial ratios including debt to total capitalization and debt to earnings before interest, taxes, depreciation, and amortization, and a certain level of 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. At September 30, 2005 and 2004, no balances were outstanding under the line of credit. The revolving credit commitment expires July 11, 2006. NOTE 4 INCOME TAXES The components of the provision (beneﬁt) for income taxes are as follows: Years Ended September 30, Current: Federal Foreign State Deferred: Federal Foreign State Total provision (beneﬁt) 2004 (in thousands) $(5,997) 4,622 (194) (1,569) 4,037 1,902 (5) 5,934 $ 4,365 2003 $(34,495) 6,870 883 (26,742) 42,835 (3,383) 1,939 41,391 $ 14,649 2005 $39,139 8,185 2,125 49,449 31,573 4,863 1,578 38,014 $87,463 69 The amounts of domestic and foreign income before income taxes and equity in income (loss) of afﬁliates are as follows: Years Ended September 30, Domestic Foreign 2005 $195,978 16,679 $212,657 2004 (in thousands) $ (2,565) 10,565 $ 8,000 2003 $31,638 2,304 $33,942 Deferred income taxes are provided for the temporary differences between the ﬁnancial reporting basis and the tax basis of the Company’s assets and liabilities. The components of the Company’s net deferred tax liabilities are as follows: September 30, Deferred tax liabilities: Property, plant and equipment Available-for-sale securities Equity investments Other Total deferred tax liabilities Deferred tax assets: Pension reserves Insurance reserves Net operating loss and foreign tax credit carryforwards Minimum tax credit carryforwards Financial accruals Other Total deferred tax assets Valuation allowance Net deferred tax assets Net deferred tax liabilities 2005 2004 (in thousands) $210,861 31,929 20,915 1,715 265,420 10,310 3,943 32,567 428 11,295 12 58,555 31,345 27,210 $188,240 28,203 17,793 1,714 235,950 7,283 4,452 56,213 3,748 7,848 1,315 80,859 35,136 45,723 $238,210 $190,227 Reclassiﬁcations have been made to the ﬁscal 2004 balances for certain components of deferred tax assets and liabilities in order to conform to the current year’s presentation. As of September 30, 2005 the Company had foreign net operating loss carryforwards for income tax purposes of $4.9 million, of which a signiﬁcant portion can be carried forward indeﬁnitely, and foreign tax credit carryforwards of approximately $31.0 million which will expire in years 2010 through 2014. The valuation allowance is primarily attributable to foreign operating loss carryforwards and foreign tax credit carryforwards for which utilization is uncertain. At this time the Company has no plans to utilize the repatriation provision under the American Jobs Creation Act. 70 Effective income tax rates as compared to the U.S Federal income tax rate are as follows: Years Ended September 30, 2005 2004 2003 U.S. Federal income tax rate Effect of foreign taxes State income taxes Other Effective income tax rate 35% 3 3 — 41% 35% 18 — 2 55% 35% 4 4 — 43% NOTE 5 SHAREHOLDERS’ EQUITY 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. Vesting requirements are determined by the Human Resources Committee of the Company’s Board of Directors. Options granted December 6, 1995, began vesting December 6, 1998, with 20 percent of the options vesting for ﬁve consecutive years. Options granted December 4, 1996, began vesting December 4, 1997, with 20 percent of the options vesting for ﬁve consecutive years. Options granted since December 3, 1997, began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years. In March 2001, the Company adopted the 2000 Stock Incentive Plan (the “Stock Incentive Plan”). The Stock Incentive Plan was effective December 6, 2000 and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options for up to 3,000,000 shares of the Company’s common stock at an exercise price not less than the fair market value of the common stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock awards. In 2005, 5,000 shares of restricted stock awards were granted. There were no restricted stock grants in ﬁscal 2004 or 2003. The following summary reﬂects the stock option activity for the Company’s common stock and related information for 2005, 2004, and 2003 (shares in thousands): 2005 2004 2003 Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant Weighted-Average Exercise Price $21.41 24.18 16.15 25.38 $22.03 $20.62 Options 4,327 469 (305) (34) 4,457 2,997 1,158 Options 3,875 611 (130) (29) 4,327 2,575 1,597 Weighted-Average Exercise Price $20.28 27.74 16.93 23.85 $21.41 $19.34 Options 4,457 463 (1,611) (65) 3,244 2,027 755 Weighted-Average Exercise Price $22.03 32.02 19.57 27.22 $24.57 $22.74 71 The following table summarizes information about stock options at September 30, 2005 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $12.79 to $19.83 $22.66 to $24.59 $26.11 to $32.02 $12.79 to $32.02 Options 595 1,366 1,283 3,244 Weighted-Average Remaining Life Weighted-Average Exercise Price 3.5 6.5 6.6 6.0 $16.35 $23.73 $29.26 $24.57 Options 595 867 565 2,027 Weighted-Average Exercise Price $16.35 $23.79 $27.86 $22.74 The weighted-average fair value of options at their grant date during 2005, 2004, and 2003 was $12.17, $10.24, and $10.72, 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 2005 4.2% 40.3% 1.0% 5.0 2004 3.7% 44.0% .8% 5.5 2003 3.1% 45.0% .8% 4.5 On September 30, 2005, the Company had 51,934,590 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 transferable apart from the common stock, until ten business 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 transferable, the Company will issue one half of one Right with each new share of common stock issued. 72 NOTE 6 EARNINGS PER SHARE A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: Basic weighted-average shares Effect of dilutive shares: Stock options Restricted stock Diluted weighted-average shares 2005 51,087 945 1 946 52,033 2004 (in thousands) 50,312 521 — 521 50,833 2003 50,039 555 2 557 50,596 At September 30, 2005, all options outstanding were included in the computation of diluted earnings per common share. 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. NOTE 7 FINANCIAL INSTRUMENTS The Company had $200 million of long-term debt outstanding at September 30, 2005 which had an estimated fair value of $215 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. 73 The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1) and assets held in a Non-qualiﬁed Supplemental Savings Plan: Equity Securities: September 30, 2005 September 30, 2004 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $30,937 $27,811 $94,000 $70,448 $ — $170 $124,937 $ 98,089 During the years ended September 30, 2005, 2004, and 2003, marketable equity available-for-sale securities with a fair value at the date of sale of $46.7 million, $30.9 million, and $18.2 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $27.0 million, $22.8 million, and $8.6 million, respectively, and the gross realized losses totaled $7 thousand in ﬁscal 2004 and $3.1 million in ﬁscal 2003. The assets held in a Non-qualiﬁed Supplemental Savings Plan are valued at fair market which totaled $7.0 million and $5.6 million at September 30, 2005 and 2004, respectively. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments. The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2005 and 2004. 74 NOTE 8 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, 2002 $ 24,846 $(1,054) $ (7,612) $ 16,180 2003 Change: Pre-income tax amount Income tax provision Amortization of swap (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 (net of $45 income tax beneﬁt) Realized gains in net income (net of $9,659 income tax) Balance at September 30, 2004 2005 Change: Pre-income tax amount Income tax provision Realized gains in net income (net of $328 income tax) Balance at September 30, 2005 29,731 (11,298) — (3,428) 15,005 39,851 31,420 (11,940) — (15,759) 3,721 43,572 24,588 (9,343) — — 982 — 982 (72) — — 72 — 72 — — — 2,421 (920) 32,152 (12,218) — 982 — 1,501 (6,111) (1,951) 742 (3,428) 17,488 33,668 29,469 (11,198) — 72 — (1,209) (7,320) (5,510) 2,094 (15,759) 2,584 36,252 19,078 (7,249) (537) 11,292 $ 47,544 (537) 14,708 $ 58,280 — — $ — — (3,416) $(10,736) 75 NOTE 9 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, Beneﬁt obligation at beginning of year Service cost Interest cost Actuarial loss Beneﬁts paid Beneﬁt obligation at end of year Change in plan assets: Years Ended September 30, 2005 2004 (in thousands) $82,222 $71,174 3,480 4,617 3,408 (3,510) $90,217 3,943 4,403 5,985 (3,283) $82,222 2005 2004 (in thousands) Fair value of plan assets at beginning of year $ 56,650 $ 53,635 Actual gain on plan assets Employer contribution Beneﬁts paid 7,565 2,250 (3,510) 6,298 — (3,283) Fair value of plan assets at end of year $ 62,955 $ 56,650 Funded status of the plan Unrecognized net actuarial loss Unrecognized prior service cost Accumulated other comprehensive loss (before tax) Accrued beneﬁt cost $(27,262) 17,445 1 (17,317) $(27,133) $(25,572) 18,211 1 (11,807) $(19,167) Weighted-average assumptions: Years Ended September 30, Discount rate Expected return on plan assets Rate of compensation increase 2005 5.50% 8.00% 5.00% 2004 5.75% 8.00% 5.00% 2003 6.25% 8.00% 5.00% 76 The Company anticipates funding of its Pension Plan will be approximately $2.8 million in ﬁscal 2006. COMPONENTS OF NET PERIODIC PENSION EXPENSE: Years Ended September 30, Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Curtailment gain Net pension expense 2005 $ 3,480 4,617 (4,378) — 987 — 2004 (in thousands) $ 3,943 4,403 (4,232) 19 761 — $ 4,706 $ 4,894 2003 $ 5,401 4,423 (3,807) 180 1,550 84 $ 7,831 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. 2006 2007 2008 2009 2010 2011-2015 Total Years Ended September 30, $4,640 $4,606 $4,524 $4,558 $4,533 $26,368 $49,229 (in thousands) Included in the Pension Plan is an unfunded supplemental executive retirement plan. The accumulated beneﬁt obligation for the deﬁned Pension Plan was $90.1 million, $75.7 million and $66.1 million at September 30, 2005, 2004, and 2003, 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. 77 The target allocation for 2006 and the asset allocation for the domestic Pension Plan at the end of ﬁscal 2005 and 2004, by asset category, follows: Asset Category U.S. equities International equities Fixed income Real estate and other Total Target Allocation Percentage of Plan Assets At September 30, 2006 56% 14 25 5 100% 2005 58% 16 24 2 100% 2004 57% 15 27 1 100% The fair value of plan assets was $63.0 million and $56.7 million at September 30, 2005 and 2004, respectively, and the expected long-term rate of return on these plan assets was 8 percent in 2005 and 2004. 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 5 percent of the participant’s compensation subject to certain limitations. Expensed Company contributions were $6.1 million, $5.6 million, and $5.6 million in 2005, 2004, and 2003, respectively. NOTE 10 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reﬂects the activity in the Company’s reserve for bad debt for 2005, 2004 and 2003: September 30, Reserve for bad debt: Balance at October 1, Provision for bad debt Write-off of bad debt Balance at September 30, 2005 $1,265 530 (4) $1,791 2004 (in thousands) 2003 $1,319 $1,337 15 (69) 45 (63) $1,265 $1,319 78 Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following: September 30, Accounts receivable: Trade receivables Investment sales receivables Prepaid expenses and other: Prepaid value added tax Restricted cash Income tax asset Prepaid insurance Deferred mobilization Other Accrued liabilities: Taxes payable – operations Workers’ compensation liabilities Payroll and employee beneﬁts Deferred income/prepays Other 2005 2004 (in thousands) $162,646 — $162,646 $116,423 16,839 $133,262 $ 5,960 $ 1,514 2,195 2,080 1,949 654 5,483 2,000 5,831 1,329 2,846 8,080 $ 18,321 $ 21,600 $ 10,263 $ 6,531 3,830 20,277 — 10,257 $ 44,627 2,877 8,678 2,844 10,961 $ 31,891 NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, Cash payments: Interest paid, net of amounts capitalized Income taxes paid NOTE 12 RISK FACTORS CONCENTRATION OF CREDIT 2005 $12,707 $29,715 2004 (in thousands) $12,653 $ 7,010 2003 $11,375 $ 5,838 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. 79 SELF-INSURANCE The Company self-insures a signiﬁcant portion of its expected losses under its worker’s compensation, general, and automobile liability programs. Insurance coverage has been purchased for individual claims that exceed $1 million or $2 million, depending on whether a claim occurs inside or outside of the United States. 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. The Company formed a wholly-owned captive insurance company, White Eagle Assurance Company (White Eagle), to provide property damage insurance for company-owned drilling rigs. The Company obtained 85 percent of land rig property insurance from a third party insurance provider in 2005 that carried a $1.0 million deductible. The Company is self insured through White Eagle for the remaining 15 percent of land rig property coverage and the $1.0 million deductible on all rig property. Additionally, the Company is self insured for up to $1.0 million per occurrence deductible under workers compensation, general, and automobile liability insurance policies for its international operations. Premiums paid to White Eagle by the drilling segments have been included in the drilling segment expenses but eliminated, along with the premium earned income, in the Consolidated Statements of Income. CONTRACT DRILLING OPERATIONS International drilling operations are signiﬁcant contributors to the Company’s revenues and net proﬁt. It is possible that operating results could be affected by the risks of such activities, including economic conditions in the international markets in which the Company operates, political and economic instability, ﬂuctuations in currency exchange rates, changes in international regulatory requirements, international employment issues, and the burden of complying with foreign laws. These risks may adversely affect the Company’s future operating results and ﬁnancial position. The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, approximately 40 percent of the Company’s billings to the Venezuelan oil company, PDVSA, are in U.S. dollars and 60 percent are in the local currency, the bolivar. In January 2003, the Venezuelan government put into effect exchange controls that ﬁxed the exchange rate at 1600 bolivares 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 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. 80 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. The exchange rate was 2150 bolivares and 1920 bolivares at September 30, 2005 and 2004, respectively. As a result of the 12 percent devaluation of the bolivar during ﬁscal 2005 (from September 2004 through August 2005), the Company experienced total devaluation losses of $.6 million during that same period. This 12 percent devaluation loss may not be reﬂective of the potential for future devaluation losses because of the exchange controls that are currently in place. However, the exact amount and timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if ﬁscal 2006 activity levels are similar to ﬁscal 2005 and if a 10 percent to 20 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $1.6 million to $2.9 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. Were this agreement to end, the Company would revert back to receiving these payments in bolivares and thus increase bolivar cash balances and exposure to devaluation. On September 28, 2005, the Company made application with the Venezuelan government requesting the approval to convert bolivar cash balances to U.S. dollars. Upon approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit those dollars as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency 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 13 CONTINGENT LIABILITIES AND COMMITMENTS COMMITMENTS During ﬁscal year 2005, the Company entered into separate drilling contracts with eight exploration and production customers to build and operate a total of 25 new FlexRigs (see Note 15 Subsequent Events regarding construction of an additional 25 new FlexRigs). The construction cost is estimated to average approximately $11 million to $14 million per rig, depending on equipment requirements. The construction began in the third quarter of ﬁscal 2005 and is estimated to continue into the fourth quarter of ﬁscal 2007. During construction, rig construction costs will be recorded in construction in progress and then transferred to contract drilling equipment when the rig is placed in the ﬁeld for service. Equipment, parts and supplies are ordered in advance to promote efﬁcient construction progress. At September 30, 2005, the Company had commitments outstanding of approximately $96.2 million for the purchase of drilling equipment. 81 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 lease agreement contains rent escalation clauses, which have been included in the future minimum lease payments below, and a renewal option. Leasehold improvements made at the inception of the lease were capitalized and are being amortized over the initial lease term. 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, 2005 are as follows (in thousands): Fiscal Year 2006 2007 2008 2009 2010 Thereafter Total Amount $3,095 2,470 1,615 1,569 482 — $9,231 Total rent expense was $2.3 million, $2.0 million and $1.1 million for 2005, 2004 and 2003, respectively. CONTINGENCIES In August 2005, the Company’s Rig 201, which operates on an operator’s tension-leg platform in the Gulf of Mexico, lost its entire derrick and suffered signiﬁcant damage as a result of Hurricane Katrina. Pre-tax cash ﬂow from the platform rig was approximately $5.4 million in ﬁscal 2005. The Company is still in the process of assessing the damage to the rig and does not anticipate that it will return to service in 2006. The rig was insured at a value that approximated replacement cost to cover the net book value and any additional losses. Therefore, the Company expects to record a gain resulting from the receipt of insurance proceeds. Because the damage assessment has not been completed, the Company is unable to estimate the amount or timing of the gain. Capital costs incurred in conjunction with any repairs will be capitalized and depreciated as described in Note 1 Summary of Signiﬁcant Accounting Policies. NOTE 14 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 mainly 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 key areas of operations include 82 a 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. The Company evaluates performance of its segments based upon operating income or loss from operations before income taxes which includes: • • • • revenues from external and internal customers direct operating costs depreciation 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 is 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 Signiﬁcant Accounting Policies. Intersegment sales are accounted for in the same manner as sales to unafﬁliated customers. 83 Summarized ﬁnancial information of the Company’s reportable segments for each of the years ended September 30, 2005, 2004, and 2003 is shown in the following table: (in thousands) 2005 Contract Drilling U.S. Land U.S. Offshore International Real Estate Other Eliminations External Sales Inter- Segment Total Sales Operating Income Depreciation Total Assets Additions to Long-Lived Assets $527,637 $ — $527,637 $164,657 $60,222 $ 809,403 $ 70,297 84,921 177,480 790,038 10,688 — — — — — 761 — 84,921 177,480 790,038 11,449 17,708 18,973 201,338 4,714 0 (26,846) (761) (761) — 10,602 20,107 90,931 2,352 2,991 — 95,108 239,087 1,143,598 32,203 487,549 — 1,058 12,438 83,793 1,517 1,495 — Total $800,726 $ — $800,726 $179,206 $96,274 $1,663,350 86,805 2004: Contract Drilling U.S. Land U.S. Offshore International Real Estate Other Eliminations Total 2003: Contract Drilling U.S. Land U.S. Offshore International Real Estate Other Eliminations Total $346,015 $ — $346,015 $ 35,545 $56,528 $ 742,642 $ 69,920 84,238 148,788 579,041 10,015 — — — — 897 — 84,238 (35,628) 148,788 579,041 10,912 12,126 12,043 3,198 — (27,503) 12,107 20,530 89,165 2,253 3,007 102,557 261,893 1,107,092 33,044 266,708 1,512 9,513 80,945 3,538 5,729 — $589,056 (897) (897) $ — $589,056 — $ (12,262) — $94,425 — $1,406,844 — $ 90,212 $273,179 $ — $273,179 $ 17,751 $44,726 $ 730,642 $213,201 112,259 109,517 494,955 9,268 — — — — 1,439 — 112,259 109,517 494,955 10,707 35,932 4,854 58,537 3,922 — (28,011) 12,799 20,092 77,617 2,535 2,361 170,580 243,918 1,145,140 31,472 241,158 7,191 12,733 233,125 7,628 2,159 — $504,223 (1,439) (1,439) $ — $504,223 — $ 34,448 — $82,513 — $1,417,770 — $242,912 84 The following table reconciles segment operating income to income before taxes and equity in income (loss) of afﬁliates as reported in the Consolidated Statements of Income (in thousands). Years Ended September 30, Segment operating income (loss) Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Income from asset sales Other Total unallocated amounts 2005 $179,206 2004 $(12,262) 2003 $ 34,448 5,809 (12,642) 26,969 13,550 (235) 33,451 1,965 (12,695) 25,418 5,377 197 20,262 2,467 (12,289) 5,529 3,689 98 (506) Income before income taxes and equity in income (loss) of afﬁliates $212,657 $ 8,000 $ 33,942 The following table presents revenues from external customers and long-lived assets by country based on the location of service provided (in thousands). Years Ended September 30, 2005 2004 2003 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $623,246 $440,268 $ 394,706 66,824 60,946 12,792 36,918 $800,726 56,297 43,363 3,698 45,430 $589,056 31,816 50,463 6,062 21,176 $ 504,223 $810,489 $799,207 $ 867,365 84,461 44,250 9,213 33,552 $981,965 85,336 46,809 9,336 57,986 $998,674 75,179 46,778 12,984 55,899 $1,058,205 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 11.1 percent, 11.4 percent, and 16.0 percent of the total operating revenues during the years ended September 30, 2005, 2004, and 2003, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.7 percent, 11.3 percent, and 11.7 percent of total operating revenues in the years ended September 30, 2005, 2004, and 2003, respectively. Revenues from a third company doing business with the contract drilling segment accounted for approximately 7.7 percent, 8.9 percent, and 14.9 percent of total operating revenues in the years ended September 30, 2005, 2004, and 2003, respectively. Collectively, the 85 receivables from these customers were approximately $38.5 million and $28.6 million at September 30, 2005 and 2004, respectively. NOTE 15 SUBSEQUENT EVENTS In October and November, 2005, the Company announced three-year term contracts had been reached with ﬁve exploration and production companies to operate 20 new FlexRig4s and ﬁve new FlexRig3s. The rigs are scheduled for delivery to the ﬁeld beginning in the third quarter of ﬁscal 2006 through the fourth quarter of ﬁscal 2007. With these contracts, the Company has now committed to build a total of 50 new FlexRigs. On December 6, 2005, a cash dividend of $.0825 per share was declared for shareholders of record on February 15, 2006, payable March 1, 2006. On December 6, 2005, the Board of Directors approved Amendment No. 1 to the Rights Agreement dated January 8, 1996. Among other things, Amendment No. 1 amends the Rights Agreement to extend the Final Expiration Date of the Rights to January 31, 2016, and to increase the exercise price of the Rights to $250 per Right. NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2005 Operating revenues Operating income Net income Basic net income per common share Diluted net income per common share (in thousands, except per share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $174,679 $185,450 $207,387 $233,210 30,919 39,310 .78 .77 37,586 22,350 .44 .43 50,818 29,825 .58 .57 59,883 36,121 .70 .68 2004 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues Asset impairment charge Operating income (loss) Net income (loss) Basic net income (loss) per common share Diluted net income (loss) per common share $134,273 $143,024 $147,691 $164,068 — 9,122 6,588 .13 .13 — 4,883 6,048 .12 .12 — 8,679 4,347 .09 .09 51,516 (34,946) (12,624) (.25) (.25) 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. 86 In the ﬁrst quarter of ﬁscal 2005, the net income includes an after-tax gain on sale of available-for-sale securities of $16.0 million, $0.31 per share, on a diluted basis. In the fourth quarter of ﬁscal 2005, the net income includes an after-tax gain on sale of available for-sale securities of $.4 million, $0.01 per share, on a diluted basis. In the ﬁrst quarter of ﬁscal 2004, the net income includes a non-monetary investment gain on the conversion of shares of common stock of a company investee pursuant to that investee being acquired of $1.2 million, $0.02 per share, on a diluted basis. 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 $32.0 million, $0.63 per share, on a diluted basis. 87 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 Cherry Creek Mortgage Company 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 Edward B. Rust, Jr.*(***) Chairman and Chief Executive Ofﬁcer State Farm Mutual Automobile Insurance Company 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 88 Stockholders’ Meeting The annual meeting of stockholders will be held on March 1, 2006. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 26, 2006. 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 5, 2005, there were 808 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. Our Transfer Agent is responsible for our shareholder records, issuance of stock certiﬁcates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efﬁciently answered by corresponding directly with The Transfer Agent at the following address: UMB Bank Security Transfer Division 928 Grand Blvd., 13th Floor Kansas City, MO 64106 Telephone: (800) 884-4225 (816) 860-5000 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 and Code of Business Conduct and Ethics; 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 22, 2005. 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 (This page intentionally left blank.) (This page intentionally left blank.)

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