HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2006 13DEC200618042693 Helmerich & Payne, Inc. is the holding Company for He l m e ri c h & Pa y n e , In c . Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore 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 available-for-sale securities valued at approximately $336 million as of September 30, 2006. 13DEC200618042693 F I N A N C I A L H I G H L I G H T S Years Ended September 30, 2006 2005 2004 Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets (in thousands, except per share amounts) $1,224,813 293,858 2.77 .1725 528,905 2,134,712 $ 800,726 127,606 1.23 .165 86,805 1,663,350 $ 589,056 4,359 .04 .1613 90,212 1,406,844 To the Co-owners of Helmerich & Payne, Inc.: We are pleased to post another year of record earnings in 2006. Net income was more than double our previous all-time high of one year ago, and it is the first time in the Company’s 86-year history that revenue has exceeded the billion dollar mark. While these milestones are significant, we also know that investors are trying to discern between yesterday’s news and future trends in our business, particularly the repercussions of a potentially warm winter and the resultant downward pressure on natural gas prices. Understandably, investors apply patterns they have seen from previous drilling cycles where drilling economics have suffered from lower commodity prices, leading to lower rig counts, falling dayrates, and an ultimate sag in earnings. We tend to be more bullish on the cycle going forward, particularly as it applies to natural gas, where we believe that supply and demand fundamentals will ultimately trump short-term pricing softness and volatility. Importantly, our business model is not just limited to market dayrate direction, but is also fueled by designing and rolling out highly innovative rigs and then building an organization focused on field execution that will exceed our customers’ expectations. From the Company’s vantage point, a key market ‘‘touchstone’’ has been our 73 new-build orders. Consider the most recent orders, seven rigs for three customers, were placed during a time of heightened market uncertainty and natural gas price volatility. But why would customers – and ours are heavily weighted toward the larger, most stable and forward looking – not simply sit on the sidelines during this current time of uncertainty to see if a shakeup does occur that frees up some rigs? Certainly, some will be inclined to pursue this course, but what is different today is that a large number of customers have experienced the value proposition of the FlexRig(cid:1). Older conventional rigs that may become available are simply not suitable for the customer’s desire for a more productive rig. The demand for a drilling solution that provides well-cost savings through improved efficiencies, safety, and reliability is driving a very rational segmentation in the industry’s drilling fleet. As we have said before, a significant retooling is occurring that will continue to provide us with growth opportunities. (cid:1)FlexRig is a registered trademark of Helmerich & Payne, Inc. But let’s assume some rough road ahead, including a flattening or even a pullback in the U.S. land drilling market. How is the Company positioned for that possibility? First, 50 percent of our potential U.S. land activity days are contracted in 2007. Moreover, we would argue that our active rigs without long-term customer commitments in the spot market are not comparable on an apples to apples basis with those of our peers. In fact, 32 out of 56 of our rigs in the spot market are FlexRigs. These rigs have worked at premium dayrates and near 100 percent activity since their introduction. The remaining 24 active rigs without long-term customer commitments also compare quite favorably to their older and less capable counterparts. In short, having the newest fleet in the business, where our completed build out will feature 122 FlexRigs in the U.S. land market, positions us well for the future. A second thing to note, besides the strong base of contracted days and attractive rigs in the spot market, is the additional activity days expected during 2007, as a result of our new-build rigs being deployed at the rate of ten to twelve per quarter. We had an average of 104 rigs active during the fourth fiscal quarter in the U.S. land market. Currently, we expect this average to grow to over 130 rigs for all of fiscal 2007, and we plan to begin fiscal 2008 with over 150 active rigs. The bottom line is that the Company is positioned to deliver significant growth without the tailwind of ever-expanding dayrate margins. The achievement in 2006 and our bright prospects for the future are products of the commitment, dedication, and tireless effort delivered over the long term by our people. I want to express my gratitude for all of their contributions to the Company’s success. Sincerely, Hans Helmerich President 11DEC200619131880 December 13, 2006 Financial & Operating Review Years Ended September 30, 2006 2005 2004 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues Operating Costs, excluding depreciation Depreciation** General and Administrative Expense Operating Income (loss) Interest and Dividend Income Gain on Sale of Investment Securities 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 and depreciation of $94,425. 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 $1,224,813 661,563 101,583 51,873 417,286 9,834 19,866 6,644 293,858 293,858 $ 800,726 484,231 96,274 41,015 192,756 5,809 26,969 12,642 127,606 127,606 $ 589,056 417,716 145,941 37,661 (6,885) 1,965 25,418 12,695 4,359 4,359 2.77 2.77 1.23 1.23 .04 .04 $ 33,853 164,143 218,309 1,483,134 2,134,712 175,000 1,381,892 528,905 $ 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 73 12 28 9 27 149 100 100 95 99 69 90 50 12 29 11 26 128 100 99 82 94 53 77 48 11 28 11 32 130 99 91 67 87 48 54 2003 2002 2001 2000 1999 1998 1997 1996 $ 504,223 346,259 82,513 41,003 38,137 2,467 5,529 12,289 17,873 17,873 $ 523,418 362,133 61,447 36,563 64,667 3,624 24,820 980 53,706 63,517 $ 528,187 331,063 49,532 28,180 123,613 9,128 1,189 1,701 80,467 144,254 $ 383,898 249,318 77,317 23,306 34,826 18,215 13,295 2,730 36,470 82,300 $ 430,475 288,969 70,092 24,629 49,024 4,830 2,547 5,389 32,115 42,788 $ 476,750 321,798 58,187 21,299 78,077 5,942 38,421 336 80,790 101,154 $351,710 227,921 48,291 15,636 61,740 6,740 4,697 34 48,801 84,186 $275,096 185,210 39,592 15,222 34,736 5,216 566 678 25,844 72,566 .18 .18 .53 .63 .79 1.42 .36 .82 .32 .43 .80 1.00 .48 .83 .26 .73 $ 38,189 110,848 158,770 1,058,205 1,417,770 200,000 917,251 242,912 $ 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 43 11 29 12 32 127 97 89 58 81 51 39 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 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 0 6 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (cid:1) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2006 OR (cid:2) 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 (Address of principal executive offices) 74119-3623 (Zip code) Securities registered pursuant to Section 12(b) of the Act: (918) 742-5531 (Registrant’s telephone number, including area code) Title of Each Class Common Stock ($0.10 par value) Preferred Stock Purchase Rights Name of Exchange On Which Registered New York Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:1) No (cid:2) Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:2) No (cid:1) 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 (cid:1) No (cid:2) 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. (cid:2) Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer (cid:1) Accelerated Filer (cid:2) Non-Accelerated Filer (cid:2) Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:2) No (cid:1) At March 31, 2006, the aggregate market value of the voting stock held by non-affiliates was $3,524,132,872. Number of shares of common stock outstanding at December 5, 2006: 103,436,828. DOCUMENTS INCORPORATED BY REFERENCE 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, 2006 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 7, 2007 10-K Parts Parts I and II Part III DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS THIS REPORT INCLUDES ‘‘FORWARD-LOOKING STATEMENTS’’ WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT’S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD- LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD- LOOKING TERMINOLOGY SUCH AS ‘‘MAY’’, ‘‘WILL’’, ‘‘EXPECT’’, ‘‘INTEND’’, ‘‘ESTIMATE’’, ‘‘ANTICIPATE’’, ‘‘BELIEVE’’, OR ‘‘CONTINUE’’ OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT’S EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION ‘‘RISK FACTORS’’ BEGINNING ON PAGE 6, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 31 THROUGH 63 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. i HELMERICH & PAYNE, INC. FORM 10-K YEAR ENDED SEPTEMBER 30, 2006 TABLE OF CONTENTS PART I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Item 3. Item 4. Item 5. Item 6. Item 7. Properties Legal Proceedings Submission of Matters to a Vote of Security Holders Executive Officers of the Company PART II Market for the Company’s Common Stock and Related Stockholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Managements Discussion & Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Item 10. Directors and Executive Officers of the Company Item 11. Executive Compensation PART III Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions Item 14. Principal Accountant Fees and Services PART IV Item 15. Exhibits and Financial Statement Schedules SIGNATURES Page 1 6 11 12 15 16 16 17 18 19 19 19 19 19 22 23 23 23 23 23 23 27 ii HELMERICH & PAYNE, INC. AND SUBSIDIARIES Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 2006 Item 1. BUSINESS PART I 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 reportable 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, Louisiana, Mississippi, and New Mexico, and offshore from platforms in the Gulf of Mexico and California. The Company also operated in eight international locations during fiscal 2006: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Equatorial Guinea, Tunisia, and Chile. 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. CONTRACT DRILLING 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 shallow to deep drilling in 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 independent oil companies. In South America, the Company’s current customers include the Venezuelan state petroleum company and major international oil companies. In fiscal 2006, the Company received approximately 57 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 2006 accounted for approximately 11 percent, 7 percent and 7 percent, respectively, of the Company’s consolidated operating revenues for the same period. The Company provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided so that the Company’s customers may explore for and develop oil and gas from onshore areas and from fixed 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 platform drilling rigs and drilling rigs to be used on tension-leg platforms and spars. The self-moving rig is designed to be moved without the use of expensive derrick barges. The tension-leg platforms and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms. During fiscal 1998, the Company put to work a new generation of six highly mobile/depth flexible land drilling rigs (individually the ‘‘FlexRig(cid:4)’’). 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. During fiscal 2005 and fiscal 2006, the Company entered into separate drilling contracts with 18 exploration and production companies to build and operate a total of 73 new FlexRigs (an increase from the 66 new FlexRigs previously announced). Of the 73 FlexRigs, 19 are FlexRig3s and 54 are FlexRig4s (described below). With the exception of one contract, 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. This 73 rig new-build project represents the single largest rig construction project in the Company’s history. Labor cost increases and labor shortages in both fabrication and rig-up services resulted in large part from Hurricanes Katrina and Rita. The hurricane-related damage significantly affected the Company’s principal fabricator of rig components and caused rig production delays and increased rig costs. Consequently, the Company completed 24 FlexRigs during fiscal 2006 rather than its original estimate of 30 rigs, and the level of capital investment estimated for the construction of the previously announced 66 FlexRigs increased by an average of 16 percent per rig from the original estimate. Delivery schedules of the new rigs were pushed back to such a degree that late-delivery contractual liquidated damage payments were incurred and are expected to be incurred for most of the remaining rigs. However, the incurred and projected liquidated damage payments had, and are expected to have, minimal impact on revenues and margins. All 73 FlexRigs are expected to be completed by the end of calendar 2007. The total FlexRig construction cost is expected to approximate $1.1 billion, or approximately $15 million per FlexRig. While the new FlexRig3s are similar to the Company’s existing FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow 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. The effective use of technology is important to the maintenance of our competitive position within the drilling industry. As a result of the importance of technology to our business, we expect to continue to develop technology internally. 2 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 2006, 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 years 2004 through 2006. 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, bankruptcy, sustained unacceptable performance by the Company, or late delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. Excluding the fixed term contracts covering the 73 FlexRig new-build project, the Company had 39 rigs under fixed term contracts as of the end of September 2006. 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. LAND DRILLING At the end of September, 2006, 2005 and 2004, the Company had 110, 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 fiscal 2006 increased by a net of 19 rigs from the end of fiscal 2005. The change from fiscal 2005 to fiscal 2006 resulted from one rig moving back from the Company’s international fleet and one rig moving to the Company’s international fleet during fiscal year 2006, the sale of one conventional rig in March of 2006, and 20 new FlexRigs placed into service. Three additional FlexRigs were completed as of September 30, 2006 and were ready for delivery. The Company’s U.S. land operations contributed approximately 68 percent of the Company’s consolidated operating revenues during fiscal 2006, compared with approximately 66 percent of consolidated operating revenues during fiscal 2005 and approximately 59 percent of consolidated operating revenues during fiscal 2004. Rig utilization in fiscal 2006 was approximately 99 percent, up from approximately 94 percent in fiscal 2005. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 100 percent during fiscal 2006 while the Company’s conventional rigs had an average utilization rate of approximately 95 percent. A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract. At the close of fiscal 2006, 109 land rigs were working out of 110 available rigs. 3 U.S. OFFSHORE PLATFORM DRILLING The Company’s offshore platform operations contributed approximately 11 percent of the Company’s consolidated operating revenues during fiscal 2006 and 2005, compared with approximately 14 percent of consolidated operating revenues during fiscal 2004. Rig utilization in fiscal 2006 was approximately 69 percent, up from approximately 53 percent in fiscal 2005. At the end of this fiscal year, the Company had seven of its nine 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 58 percent of U.S. offshore platform revenues during fiscal 2006. During the fourth quarter of 2006, the Company signed an option agreement to sell two offshore rigs. If the option is exercised, the sale is expected to be completed in the second quarter of fiscal 2007. The two rigs have been classified as assets held for sale in the Company’s Consolidated Financial Statements and as such, are excluded from the number of owned rigs at the end of 2006. The Company’s offshore platform Rig 201 sustained significant damage from Hurricane Katrina in 2005. The Company anticipates Rig 201 returning to service during fiscal 2007. The rig was insured at a value that approximated replacement cost. INTERNATIONAL DRILLING General The Company’s international drilling operations began in 1958 with the acquisition of Sinclair Oil Company’s drilling rigs in Venezuela. Helmerich & Payne de Venezuela, C.A., a wholly owned subsidiary of the Company, is one of the leading drilling contractors in Venezuela. Beginning in 1972, with the introduction of its first helicopter rig, the Company expanded into other Latin American countries. The Company’s international operations contributed approximately 21 percent of the Company’s consolidated operating revenues during fiscal 2006, compared with approximately 22 percent of consolidated operating revenues during fiscal 2005 and approximately 25 percent of consolidated operating revenues during fiscal 2004. Rig utilization in fiscal 2006 was 90 percent, up from 77 percent in fiscal 2005. Venezuela Venezuelan operations continue to be a significant part of the Company’s operations. During fiscal 2006, the Company moved a conventional rig to the United States, reducing the rig count to 11 in Venezuela. The Company worked for the Venezuelan state petroleum company, PDVSA, during fiscal 2006 and revenues from this work accounted for approximately 33 percent of international operating revenues. Revenues generated from Venezuelan drilling operations contributed approximately 7 percent ($84.6 million) of the Company’s consolidated operating revenues during 2006, compared with approximately 8 percent ($66.8 million) of consolidated operating revenues during fiscal 2005 and 10 percent ($56.3 million) of consolidated operating revenues during 2004. The Company had ten rigs working in Venezuela at the end of fiscal 2006. The Company’s rig utilization rate in Venezuela increased from approximately 72 percent during fiscal 2005 to approximately 83 percent in fiscal 2006. The Company expects to return one idle rig back to work during the first quarter of fiscal 2007. At this time, the Company is unable to predict future fluctuations in its utilization rates. Ecuador At the end of fiscal 2006, the Company owned eight rigs in Ecuador. The Company’s utilization rate was 100 percent during fiscal 2006, up from approximately 97 percent in fiscal 2005. Revenues generated by Ecuadorian drilling operations contributed approximately 7 percent ($88.7 million) of the Company’s consolidated operating revenues during fiscal 2006, as compared with approximately 8 percent ($60.9 million) of consolidated operating revenues during fiscal 2005 and approximately 7 percent ($43.4 million) of consolidated operating revenues during fiscal 2004. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 3 percent of consolidated 4 operating revenues and approximately 14 percent of international operating revenues during fiscal 2006. The Ecuadorian drilling contracts are primarily with large international oil companies. Other Locations In addition to its operations in Venezuela and Ecuador, at the end of fiscal 2006, the Company owned three rigs in Argentina, two rigs in Colombia and one rig each in Bolivia, Chile, and Tunisia. At the end of November 2006, three rigs were working in Argentina, and Tunisia, Chile and Bolivia each had one rig working. During fiscal 2006, 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. REAL ESTATE OPERATIONS The Company’s real estate operations are conducted exclusively within the metropolitan area of Tulsa, Oklahoma. Its major holding is Utica Square Shopping Center, consisting of 15 separate buildings, with parking and other common facilities covering an area of approximately 30 acres. Utica Square contains approximately 441,588 usable square feet, composed of retail space of 379,018 usable square feet, office space of 38,785 usable square feet, storage space of 6,600 usable square feet and common area space of 17,185 usable square feet. The Company’s real estate operations occupy approximately 4,140 square feet of general office and storage space within the shopping center. Occupancy in the shopping center increased from 91 percent in fiscal 2005 to 92 percent in fiscal 2006. At the end of the 2006 fiscal year, the Company owned 11 of a total of 73 units in The Yorktown, a 16-story luxury residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to Utica Square Shopping Center. Seven of the Company’s units are currently leased. The Company owns 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 79 percent, which is down from approximately 89 percent one year ago. The decrease in occupancy is due to the loss of two 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 2006, 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 decreased to approximately 76 percent in 2006 from approximately 89 percent in fiscal 2005 due to the loss of one tenant. 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 decreased from approximately 76 percent in 2005 to approximately 72 percent during fiscal 2006 due to the loss of one tenant. 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 2006, occupancy increased from approximately 69 percent to approximately 74 percent due to the addition of one new tenant. 5 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 2006, occupancy has increased to approximately 61 percent from approximately 56 percent due to the addition of one 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 2006, occupancy remained unchanged at approximately 63 percent. The Company’s offsite disaster recovery center occupies approximately 3,517 square feet of office and computer equipment space in this property. The Company also owns approximately 8.4370 acres of vacant land, which was the site of its former headquarters. No development plans for the site are pending. FINANCIAL Information relating to revenues, total assets and operating income or loss by business segments may be found on, and is incorporated by reference to, pages 95 through 99 of the Company’s Annual Report. EMPLOYEES The Company had 4,302 employees within the United States (eight of which were part-time employees) and 1,403 employees in international operations as of September 30, 2006. AVAILABLE INFORMATION Information relating to the Company’s internet address and the Company’s SEC filings may be found on, and is incorporated by reference to, page 101 of the Company’s Annual Report. Item 1A. RISK FACTORS 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. 6 2. Operating and Weather 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. Specifically, the Company operates several platform rigs in the Gulf of Mexico. The Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis. Damage caused by high winds and turbulent seas could potentially curtail operations on such platform rigs for significant periods of time until the damage can be repaired. Moreover, even if the Company’s platform rigs are not directly damaged by such storms, the Company may experience disruptions in operations due to damage to customer platforms and other related facilities in the area. Until 2005, the Company’s platform operation had not been materially affected by adverse weather. In August of 2005, platform Rig 201 sustained significant hurricane damage. This rig is not expected to return to normal drilling operations until fiscal 2007. The Company’s new-build rig assembly facility is located near the Houston, Texas ship channel. Also, the Company’s principal fabricator and other vendors are located in the Gulf Coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage. 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, bankruptcy, sustained unacceptable performance by the Company, or late delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. 4. Indemnification and Insurance Coverage The Company has insurance coverage for comprehensive general liability, automobile liability, worker’s compensation, employer’s liability, and property damage. Generally, deductibles are $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 reduce the Company’s exposure to catastrophic events. In fiscal 2006, the Company obtained property insurance for 85 percent of the aggregate estimated replacement cost of its rigs in excess of a $1 million deductible. If loss levels exceed a set percentage of excess property premium in fiscal 2006, then the Company would share in losses up to a maximum of $5 million. The Company self-insured the remaining 15 percent of such rig value including deductibles. 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 has been purchased through fiscal 2007. Multiple hurricanes in the Gulf of Mexico during August and September of 2005 continued to have a severe impact on the availability and price of the Company’s rig property coverage for 2007. As a result, the Company transferred only 80 percent of its rig property exposure in excess of a $1 million per occurrence deductible to third party insurers. Insurance coverage for named storms in the Gulf of Mexico is also limited to a net aggregate of $60 million. No assurance can be given that all or a portion of the Company’s coverage will 7 not be cancelled during fiscal 2007 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. Limited Number of Vendors Certain key rig components are either purchased from or fabricated by a single or limited number of vendors, and the Company has no long-term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply or increased demands in the industry. If the Company was unable to procure certain of such rig components, it would be required to reduce its rig construction or other operations, which could have a material adverse effect on the Company’s business, financial condition and results of operations. If the Company’s principal fabricator, located on the Texas Gulf Coast, was unable or unwilling to continue fabricating rig components, then the Company would have to transfer this work to other acceptable fabricators. This transfer could result in significant delay in the completion of new FlexRigs. Any significant interruption in the fabrication of rig components could have a material adverse impact on the Company’s business, financial condition, and results of operations. 7. Thinly Capitalized Vendors Certain key rig components are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from the Company or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business or by any downturn in the energy industry. Therefore, disruptions in rig component delivery may occur, and such disruptions and terminations could have a material adverse effect on the Company’s business, financial condition, or results of operations. 8. Volatility of Oil and Gas Prices The Company’s operations can be materially affected by low oil and gas prices. The Company believes that any significant reduction in oil and gas prices could depress the level of exploration and production activity and result in a corresponding decline in demand for the Company’s services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for the Company’s services could have a material and adverse effect on the Company. 9. 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. 8 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. Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in labor and/or material and supplies necessary to operate some or all of its Venezuelan drilling rigs, thereby causing an adverse effect on the Company. 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. Although the Company attempts to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2006, approximately 21 percent of the Company’s consolidated operating revenues were generated from the international contract drilling business. Approximately 91 percent of the international operating revenues were from operations in South America and approximately 76 percent of South American operating revenues were from Venezuela and Ecuador. 10. 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, Bolivia, Equatorial Guinea, Chile, and Tunisia. 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 $.3 million in Argentina currency losses in fiscal 2006. Venezuela The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 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. 9 dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S. based parent. This was the first dividend remitted under the new regulation. On January 16, 2006, a dividend of $6.5 million U.S. dollars was remitted to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation has been reduced by these amounts. On August 18, 2006, 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 approximately $9.3 million as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation. 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. Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Even though Venezuela continues to operate under the exchange controls in place and the Venezuelan bolivar exchange rate has remained fixed at 2150 bolivares to one U.S. dollar since the devaluation in March 2005, the exact amount and timing of devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2007 activity levels are similar to fiscal 2006, and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.5 million to $2.8 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. 11. Increased Receivables in Venezuela The Company derives its revenue in Venezuela from PDVSA, the Venezuelan state-owned petroleum company. At the end of fiscal 2006, the Company had a net receivable from PDVSA of approximately $45 million, of which approximately $16 million was 90 days old or older. At December 1, 2006, such receivable balance had increased to approximately $66 million, of which approximately $40 million was 90 days old or older. The aggregate receivable amount of $66 million approximates the historical high for the Company’s receivables in Venezuela. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than those of other foreign customers of the Company. However, the failure of PDVSA to make payments on outstanding receivables, or a continued increase in its delay in making payments could have a material adverse effect on the Company’s financial condition and results of operations. In order to establish a source of local currency to meet current obligations in Venezuela bolivares, the Company is borrowing in the form of short-term notes from two local banks in Venezuela at the market interest rates designated by the banks. 12. 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 10 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. 13. 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, 2006, 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, 2006 was approximately $209 million. At September 30, 2006, the Company had in place a committed unsecured line of credit totaling $50 million with no outstanding borrowings. The Company, as of September 30, 2006, had letters of credit totaling $16.4 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. In December 2006, the Company expects to enter into a five-year $400 million senior unsecured credit facility. Borrowings under this credit facility will be subject to floating interest rates. If the Company enters into this senior unsecured credit facility then the existing $50 million unsecured line of credit will be reduced to $5 million. 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. 14. Equity Price Risk At September 30, 2006, the Company had a portfolio of available-for-sale securities with a total market value of $336.1 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. and investments in limited partnerships carried at cost, 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. 15. Reliance on Small Number of Customers In fiscal 2006, the Company received approximately 57 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers and approximately 25 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. 16. 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. 17. 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. 18. 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. Item 1B. UNRESOLVED STAFF COMMENTS The Company has received no written comments regarding its periodic or current reports from the staff of the Securities and Exchange Commission that were issued 180 days or more preceding the end of its 2006 fiscal year and that remain unresolved. 11 Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning the Company’s U.S. drilling rigs as of September 30, 2006: Location FLEXRIGS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS WYOMING WYOMING OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS LOUISIANA TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS Rig Optimum Depth Rig Type Drawworks: Horsepower 164 165 166 167 168 169 178 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 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) 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) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location COLORADO TEXAS WYOMING TEXAS TEXAS COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO NEW MEXICO NEW MEXICO NEW MEXICO WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS COLORADO COLORADO TEXAS TEXAS HIGHLY MOBILE RIGS OKLAHOMA OKLAHOMA TEXAS WYOMING OKLAHOMA TEXAS LOUISIANA TEXAS TEXAS TEXAS TEXAS WYOMING CONVENTIONAL RIGS TEXAS OKLAHOMA TEXAS OKLAHOMA TEXAS TEXAS WYOMING TEXAS OKLAHOMA LOUISIANA TEXAS OKLAHOMA OKLAHOMA Rig 239 240 241 243 245 271 272 273 274 275 276 277 278 281 282 283 284 285 286 287 288 289 290 291 293 294 140 158 156 159 141 142 143 145 155 146 147 154 110 96 118 119 120 171 172 122 162 79 80 89 92 Optimum Depth Rig Type Drawworks: Horsepower AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig4) AC (FlexRig4) AC FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) Mechanical SCR Mechanical Mechanical Mechanical Mechanical Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Mechanical SCR SCR SCR SCR SCR SCR 18,000 18,000 18,000 18,000 18,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 8,000 8,000 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 8,000 14,000 14,000 10,000 10,000 12,000 12,000 14,000 14,000 14,000 14,000 14,000 16,000 16,000 16,000 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 13 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 1,150 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 1,500 1,500 900 900 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,500 700 1,000 1,200 1,200 1,200 1,000 1,000 1,700 1,500 2,000 1,500 1,500 1,500 Location OKLAHOMA OKLAHOMA TEXAS LOUISIANA TEXAS TEXAS TEXAS LOUISIANA OKLAHOMA TEXAS LOUISIANA MISSISSIPPI TEXAS LOUISIANA LOUISIANA OFFSHORE PLATFORM RIGS GULF OF MEXICO GULF OF MEXICO LOUISIANA GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO Rig 94 98 97 99 137 149 148 72 73 125 134 136 157 161 163 203 205 206 100 105 107 201 202 204 Optimum Depth Rig Type Drawworks: Horsepower 20,000 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 20,000 20,000 20,000 30,000 30,000 30,000 30,000 30,000 30,000 SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Self-Erecting Tension-leg Self-Erecting Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 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 2,500 2,000 1,500 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of the Company’s U.S. land and offshore drilling rigs for the periods indicated: Years ended September 30, 2002 2003 2004 2005 2006 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) . . . . . . . . . . . . . . . . . . . . . 83 66 84% 81% 87% 94% 99% 113 87 91 12 12 83% 51% 48% 53% 69% 11 11 9 (1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. 14 The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2006: Location Argentina Argentina Argentina Bolivia Chile Colombia Colombia Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Ecuador Tunisia Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 139 175 177 151 123 133 152 22 23 132 176 121 117 138 190 242 160 113 115 116 127 128 129 135 150 174 153 Optimum Depth Rig Type Drawworks: Horsepower 30,000+ 30,000 30,000 30,000+ 26,000 30,000 30,000+ 18,000 18,000 18,000 18,000 20,000 26,000 26,000 26,000 18,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000+ SCR SCR SCR SCR SCR SCR SCR SCR (Heli Rig) SCR (Heli Rig) SCR SCR SCR SCR SCR SCR AC (FlexRig3) SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 3,000 3,000 3,000 3,000 2,100 3,000 3,000 1,700 1,500 1,500 1,500 1,700 2,500 2,500 2,000 1,500 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of the Company’s international drilling rigs for the periods indicated: Years ended September 30, 2002 2003 2004 2005 2006 Number of rigs owned at end of Period . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1)(2) . . . . . . . . . . . . . . . . . . . . . 32 33 32 51% 39% 54% 77% 90% 27 26 (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 the United States for major modifications and upgrades. REAL ESTATE OPERATIONS See Item 1. BUSINESS, pages 5 through 6 of this Report, which is incorporated herein by reference. STOCK PORTFOLIO Information required by this item regarding the stock portfolio held by the Company may be found on, and is incorporated by reference to, page 52 of the Company’s Annual Report under the caption, ‘‘Management’s Discussion & Analysis of Financial Condition and Results of Operations.’’ Item 3. LEGAL PROCEEDINGS 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 15 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. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE COMPANY The following table sets forth the names and ages of the Company’s executive officers, together with all positions and offices held with the Company by such executive officers. Officers are elected to serve until the meeting of the Board of Directors following the next Annual Meeting of Stockholders and until their successors have been elected and have qualified or until their earlier resignation or removal. W. H. Helmerich, III, 83 Chairman of the Board; Director since 1949; Chairman of the Board since 1960 Hans Helmerich, 48 . . . President and Chief Executive Officer; Director since 1987; President and Chief Executive Officer since 1989 Douglas E. Fears, 57 . . . Vice President and Chief Financial Officer since 1988 Steven R. Mackey, 55 . . Vice President, Secretary and General Counsel; Secretary since 1990; Vice President and General Counsel since 1988 John W. Lindsay, 45 . . . Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. since 2006; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. since 1997 M. Alan Orr, 55 . . . . . . Executive Vice President, Drilling Technology and Development of Helmerich & Payne International Drilling Co. since 2006; Vice President and Chief Engineer of Helmerich & Payne International Drilling Co. since 1992 16 PART II Item 5. MARKET FOR THE COMPANY’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 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 2005 2006 High Low High Low First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $17.080 20.550 23.460 30.560 $13.830 15.785 18.690 23.805 $32.375 39.350 39.950 30.455 $24.945 30.420 26.375 22.020 The Registrant paid quarterly cash dividends during the past two years as shown in the following table: Quarter Paid per Share Fiscal Total Payment Fiscal 2005 2006 2005 2006 First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $.04125 .04125 .04125 .04125 $.04125 .04125 .04500 .04500 $4,165,965 4,213,594 4,226,835 4,259,852 $4,290,909 4,333,069 4,344,984 4,743,331 The Company paid a cash dividend of $0.0450 per share on December 1, 2006, to shareholders of record on November 15, 2006. Payment of future dividends will depend on earnings and other factors. All per share amounts have been adjusted as a result of a two-for-one stock split effective June 26, 2006. As of December 5, 2006, there were 758 record holders of the Company’s common stock as listed by the transfer agent’s records. Summary of All Existing Equity Compensation Plans The following chart sets forth information concerning the equity compensation plans of the Company as of September 30, 2006. EQUITY COMPENSATION PLAN INFORMATION (1) Plan Category 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)) Equity compensation plans approved by security holders (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,618,828 $14.2438 4,000,000 (a) (b) (c) Equity compensation plans not approved by security holders (3) . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 5,618,828 — $14.2438 — 4,000,000 (1) All information has been adjusted as a result of a two-for-one stock split effective June 26, 2006. (2) Includes the 1996 Stock Incentive Plan, the 2000 Stock Incentive Plan, and the 2005 Long-Term Incentive Plan of the Company. 17 (3) The Company does not maintain any equity compensation plans that have not been approved by the stockholders. Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table reflects purchases made during the 2006 fiscal year: ISSUER PURCHASES OF EQUITY SECURITIES (1) Period (a) Total Number of Shares (or Units) Purchased (d) Maximum Number (or Approximate Dollar Value) of Shares (or (b) Average Price Purchased as Part of Units) That May Yet Paid Per Share (or Publicly Announced Be Purchased Under Plans or Programs Plans or Programs (c) Total Number of Shares (or Units) Unit) July 1–July 31, 2006 . . . . . . . . . . . . August 1–August 31, 2006 . . . . . . . . September 1–September 30, 2006 . . TOTAL . . . . . . . . . . . . . . . . . . . . . — — 1,325,200 1,325,200 — — $22.7656 $22.7656 — — — — — — 2,674,800 2,674,800 (1) The Company has a program to repurchase its Common Stock in the open market. On December 5, 2001, the Company’s Board of Directors authorized a stock repurchase program for the repurchase of up to two (2) million shares per calendar year, with such annual authorization being adjusted to four (4) million shares due to the two-for-one stock split effective June 26, 2006. The repurchases may be made using the Company’s cash reserves or other available sources. The program has no expiration date but may be terminated at any time at the Board of Directors’ discretion. The Company plans to continue making open-market purchases of its stock on an opportunistic basis. All shares reported in the above table were purchased in the open market other than through a publicly announced plan or program. No other purchases were made in fiscal 2006. Item 6. SELECTED FINANCIAL DATA 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 Financial Condition and Results of Operations contained on pages 31 through 63 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. All per share amounts have been adjusted as a resulf of a two-for-one stock split effective June 26, 2006. Five-year Summary of Selected Financial Data Operating revenues . . . . . . . . . . . . . . . . . . . . Asset Impairment . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . . . . Income from continuing operations per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . . . . Cash dividends declared per common share . . . 2002 2003 2004 2005 2006 $ 523,418 — 53,706 (in thousands except per share amounts) $ 800,726 $ 589,056 $ 504,223 51,516 — — 127,606 4,359 17,873 $1,224,813 — 293,858 0.54 0.53 1,227,313 100,000 0.155 0.18 0.18 1,417,770 200,000 0.16 0.04 0.04 1,406,844 200,000 0.16125 1.25 1.23 1,663,350 200,000 0.165 2.81 2.77 2,134,712 175,000 0.1725 18 Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Information required by this item may be found on, and is incorporated by reference to, pages 31 through 63 of the Company’s Annual Report under the caption ‘‘Management’s Discussion & Analysis of Financial Condition and Results of Operations.’’ Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found under the caption ‘‘Risk Factors’’ beginning on page 6 of this Report and on, and is incorporated by reference to, the following pages of the Company’s Annual Report under Management’s Discussion & Analysis of Financial Condition and Results of Operations and in Notes to Consolidated Financial Statements: Market Risk (cid:127) Foreign Currency Exchange Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:127) Credit Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:127) Commodity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:127) Interest Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:127) Equity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found on, and is incorporated by reference to, pages 65 through 100 of the Company’s Annual Report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND Page 59-60 60-61 61-62 62 63 FINANCIAL DISCLOSURE None. Item 9A. CONTROLS AND PROCEDURES 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 (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2006. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer conclude that: (cid:127) 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 (cid:127) 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 19 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 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, 2006. The Company’s independent registered public accounting firm that audited the Company’s financial statements, Ernst & Young LLP, has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. This report appears below. 20 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, 2006, 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, 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, 2006, 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, 2006, 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, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2006 of Helmerich & Payne, Inc. and our report dated December 7, 2006, expressed an unqualified opinion thereon. Tulsa, Oklahoma December 7, 2006 Ernst & Young LLP 21 c) Changes in Internal Controls Over Financial Reporting There were no changes in the Company’s internal controls over financial reporting during the Company’s fourth fiscal quarter of 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 9B. OTHER INFORMATION None. 22 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY Information required under this item with respect to Directors, audit committees, and other disclosures under Item 401 of Regulation S-K, as well as 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 7, 2007, to be filed with the Commission not later than 120 days after September 30, 2006. The Company has adopted a Code of Ethics applicable to its CEO, CFO 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. The Company intends to disclose any amendments to or waivers from its Code of Ethics on its website. Item 11. EXECUTIVE COMPENSATION This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2007, to be filed with the Commission not later than 120 days after September 30, 2006. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2007, to be filed with the Commission not later than 120 days after September 30, 2006. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2007, to be filed with the Commission not later than 120 days after September 30, 2006. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2007, to be filed with the Commission not later than 120 days after September 30, 2006. Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV a) 1. Financial Statements: The following appear in the Company’s Annual Report to Stockholders on the pages indicated below and are incorporated herein by reference: Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Income for the Years Ended September 30, 2006, 2005 and 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 65 Consolidated Balance Sheets at September 30, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . 66-67 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2006, 2005 and 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2006, 2005 and 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 69 Notes to Consolidated Financial Statements At September 30, 2006 . . . . . . . . . . . . . . . . 70-100 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. 23 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 Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. 3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on March 2, 2006, 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 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, SEC File No. 001-04221. *10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Company dated March 30, 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 Amendment to Consulting Services Agreement between W. H. Helmerich, III, and the Company dated December 26, 1990. *10.3 *10.4 *10.5 Second Amendment to Consulting Services Agreement between W. H. Helmerich, III, and the Company dated September 11, 2006, is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed September 13, 2006, SEC File No. 001-04221. 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. 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. 24 *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. is incorporated herein by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 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. is incorporated herein by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 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. is incorporated herein by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 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 Fifth Amendment to Credit Agreement dated July 11, 2006, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.4 of the Company’s Form 8-K filed on July 11, 2006, SEC File No. 001-04221. 10.19 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221. 10.20 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. *10.21 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, SEC File No. 001-04221. 25 10.22 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. 10.23 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, SEC File No. 001-04221. *10.24 Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 9, 2005, SEC File No. 001-04221. *10.25 Advisory Services Agreement dated February 17, 2006, between Helmerich & Payne, Inc. and George S. Dotson is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on February 21, 2006, SEC File No. 001-04221. *10.26 Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix ‘‘A’’ to the Company’s Proxy Statement on Schedule 14A filed January 26, 2006. *10.27 Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement. 10.28 Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 7, 2006, SEC File No. 001-04221. 13. The Company’s Annual Report to Shareholders for fiscal 2006. 21. List of Subsidiaries of the Company. 23.1 Consent of Independent Registered Public Accounting Firm. 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, 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. 26 14DEC200616084291 27 CERTIFICATION I, Hans Helmerich, certify that: 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc. (the ‘‘Company’’); 2. 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; 3. 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; 4. 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 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; and (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 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, 2006 /S/ Hans Helmerich Hans Helmerich President and Chief Executive Officer 28 CERTIFICATION I, Douglas E. Fears, certify that: 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc. (the ‘‘Company’’); 2. 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; 3. 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; 4. 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 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; and (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 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, 2006 /S/ Douglas E. Fears Douglas E. Fears Vice President and Chief Financial Officer 29 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, 2006 as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), Hans Helmerich, as President and Chief Executive Officer of the Company, and Douglas E. Fears, as Vice President and 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) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); 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 President and Chief Executive Officer Date: December 13, 2006 /s/ Douglas E. Fears Douglas E. Fears Vice President and Chief Financial Officer Date: December 13, 2006 30 Management’s Discussion & Analysis of Financial Condition and Results of Operations Helmerich & Payne, Inc. R I S K F A C T O R S A N D F O RWA R D - L O O K I N G S TAT E M E N T S The following discussion should be read in conjunction with the consolidated financial statements and related notes included elsewhere herein. The Company’s future operating results may be affected by various trends and factors, which are beyond the Company’s control. These include, among other factors, fluctuations in oil and natural gas prices, expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, and uncertain business conditions that affect the Company’s businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends. With the exception of historical information, the matters discussed in Management’s Discussion & Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. The Company cautions that, while it believes such assumptions to be reasonable and makes them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. The Company is including this cautionary statement to take advantage of the ‘‘safe harbor’’ provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 6 of the Company’s Annual Report on Form 10K 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 31 undertakes no 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 149 drilling rigs at September 30, 2006. The Company’s contract drilling business includes the U.S. land rig business in which the Company owned 113 rigs, the U.S. offshore platform rig business in which the Company owned nine offshore platform rigs, and the international land rig business in which the Company owned 27 rigs at year end. Crude oil and natural gas prices continued to rise during 2006 due to the uncertainty of both commodities. The hurricanes in 2005 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 total demand in the U.S. As exploration and production companies expanded their drilling programs as a result of higher commodity prices, the overall demand for drilling rig services increased in all segments during 2006. R E S U LT S O F O P E R AT I O N S All per share amounts included in the Results of Operations discussion are stated on a diluted basis. All prior period common stock and applicable share and per share amounts have been retroactively adjusted to reflect a 2-for-1 split of the Company’s common stock effective June 26, 2006. The Company’s net income for 2006 was $293.9 million ($2.77 per share), compared with $127.6 million ($1.23 per share) for 2005 and $4.4 million ($0.04 per share) for 2004. 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 $0.31 per share). Included in the 32 Company’s net income were after-tax gains from the sale of investment securities of $12.3 million ($0.12 per share) in 2006, $16.4 million ($0.16 per share) in 2005, and $14.1 million ($0.14 per share) in 2004. In addition to income from security sales, the Company recorded net income during 2004 of $1.5 million ($0.02 per share) from non-monetary investment gains. Also included in net income is the Company’s portion of income from its equity affiliate, Atwood Oceanics, Inc. From the equity affiliate, the Company recorded net income of $0.07 per share in 2006, $0.02 per share in 2005 and $0.01 per share in 2004. (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 $1,224.8 million in 2006, $800.7 million in 2005, and $589.1 million in 2004. 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 96 rigs in 2006, 90 rigs in 2005 and 86 rigs in 2004. U.S. land rig utilizations for the Company were 99 percent in 2006, 94 percent in 2005 and 87 percent in 2004. Revenue in the offshore platform business increased in 2006 after remaining steady in 2005 and 2004. The demand for offshore rigs increased in the Gulf of Mexico after the hurricanes in 2005. Rig utilization for U.S. offshore rigs increased to 69 percent in 2006 compared to 53 percent in 2005 and 48 percent in 2004. International rig revenues increased from 2004 to 2006, as rig utilizations improved to 90 percent in 2006, from 77 percent in 2005 and 54 percent in 2004. Gains from the sale of investment securities were $19.9 million in 2006, $27.0 million in 2005, and $25.4 million in 2004. Interest 33 and dividend income increased to $9.8 million in 2006 from $5.8 million in 2005 and $2.0 million in 2004. The increases from 2004 are due to increased cash positions from the sale of equity securities, the sale of two U.S. land rigs in 2005 and increased cash flow. In late 2005 and during 2006, the Company’s cash position decreased as new FlexRigs were constructed. Direct operating costs in 2006 were $661.6 million or 54 percent of operating revenues, compared with $484.2 million or 60 percent of operating revenues in 2005, and $417.7 million or 71 percent of operating revenues in 2004. The 2006 expense to revenue percentage decrease from 2005 and 2004 was primarily due to higher U.S. land revenue per day resulting from higher dayrates and increased activity. Depreciation expense was $101.6 million in 2006, $96.3 million in 2005 and $94.4 million in 2004. Depreciation expense increased over the three-year period as the Company placed into service five new rigs in 2004 and 20 new rigs in 2006. The Company anticipates 2007 depreciation expense to increase from 2006 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 2006 and 2005, 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. 34 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 and makeup to existing platforms, and competitive dynamics due to lower industry utilization. General and administrative expenses totaled $51.9 million in 2006, $41.0 million in 2005, and $37.7 million in 2004. The increase from 2005 to 2006 was primarily due to recording $9.8 million of stock-based compensation. Stock-based compensation includes $7.0 million related to the adoption of SFAS 123(R) ‘‘Share-Based Payment’’ and $2.8 million due to the Company accelerating the vesting of share options held by a senior executive who retired. The Company also experienced increases in employee benefits due to an increase in the number of employees. 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. Interest expense was $6.6 million in 2006, $12.6 million in 2005, and $12.7 million in 2004. The interest expense in each year is primarily attributable to the $200 million of intermediate debt outstanding. Capitalized interest was $6.1 million, $0.3 million and $0.5 million in 2006, 2005 and 2004, respectively. The increase in capitalized interest in 2006 is attributable to the rig build program. The provision for income taxes totaled $154.4 million in 2006, $87.5 million in 2005, and $4.4 million in 2004. Effective income 35 tax rates were 35 percent in 2006, 41 percent in 2005, and 55 percent in 2004. In 2006, the Company had a lower effective tax rate primarily as a result of adjustments to deferred tax accounts in certain international locations. 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 operating income, was 14 percent in 2006, 10 percent in 2005 and 27 percent in 2004 (excluding the asset impairment charge from total operating income). 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. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets assumes, based on estimates and assumptions, that the Company will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances will be recorded against the deferred tax assets resulting in additional income tax expense in the future. (See Note 4 of the Financial Statements for additional income tax disclosures.) The following tables summarize operations by business segment. Segment operating income is described in detail in Note 15 to the financial statements. 36 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 6 A N D 2 0 0 5 U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment 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 2006 2005 % Change (in thousands, except operating statistics) $829,062 398,873 12,807 66,127 $351,255 34,414 $ 22,751 $ 10,250 $ 12,501 113 99% $527,637 294,164 8,594 60,222 $164,657 30,968 $ 15,941 $ $ 8,403 7,538 91 94% 57.1% 35.6 49.0 9.8 113.3 11.1% 42.7 22.0 65.8 24.2 5.3 Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses. Rig utilization excludes three FlexRigs completed and ready for delivery. The Company’s U.S. land rig segment operating income increased to $351.3 million in 2006 from $164.7 million in 2005. Improvement in revenue and margin per day due to higher levels of U.S. land rig activity and higher dayrates experienced during 2005 continued in 2006, as crude oil and natural gas prices reached historically high levels. Rig utilization increased to 99 percent in 2006 from 94 percent in 2005. Average rig expense per day increased 22 percent as the energy industry experienced increased demand for materials, supplies and labor. The total number of rigs owned at September 30, 2006 was 113 compared to 91 rigs at September 30, 2005. The increase is due to 20 new FlexRigs placed into service, three FlexRigs completed and ready for delivery and the sale of one conventional rig in March 2006. Depreciation in 2006 increased 9.8 percent from 2005 due to the increase in available rigs. During 2005 and 2006 the Company announced plans to build 66 new FlexRigs for 16 exploration and production companies 37 representing a 73 percent expansion to the U.S. land fleet. Subsequent to September 30, 2006, the Company announced that agreements had been reached with three exploration and production companies to operate an additional seven new FlexRigs bringing the total of the new rigs to 73. Each new rig will be operated by the Company under a minimum fixed contract term agreement with at least a three-year term. The drilling services will be performed on a daywork contract basis. During 2006, the U.S. Land segment had 20 new FlexRigs placed into service and three additional rigs completed, ready for delivery. The remaining rigs are expected to be delivered by the end of calendar 2007. As a result of the new FlexRigs, the Company anticipates depreciation expense to increase in fiscal 2007. 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 6 A N D 2 0 0 5 U.S. OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment 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 2006 2005 % Change (in thousands, except operating statistics) $132,580 88,293 5,920 11,360 $ 27,007 2,743 $ 38,728 $ 24,041 $ 14,687 9 69% $84,921 52,786 3,825 10,602 $17,708 2,122 $29,228 $15,967 $13,261 11 53% 56.1% 67.3 54.8 7.1 52.5 29.3% 32.5 50.6 10.8 (18.2) 30.2 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. Segment operating income in the Company’s U.S. offshore segment increased 52.5 percent from 2005 to 2006. An increase in the demand for offshore rigs in the Gulf of Mexico after the hurricanes in 2005 contributed to increases in activity days and rig utilization. 38 During the fourth quarter of fiscal 2006, the Company signed an option agreement to sell two offshore rigs that are currently idle. If the purchase option is exercised, the transaction is expected to be completed in the second quarter of fiscal 2007. The two rigs have been classified as assets held for sale in the Company’s Consolidated Financial Statements and, as such, are excluded from the number of owned rigs at the end of fiscal 2006. During the fourth quarter of fiscal 2005, the Company’s Rig 201 was damaged by Hurricane Katrina. Fiscal 2005 segment operating income was negatively impacted by approximately $.6 million due to the rig being removed from service during the fourth quarter. The Company anticipates Rig 201 returning to work during fiscal 2007. 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. At September 30, 2006, the Company had received insurance proceeds of approximately $3.0 million which approximated the net book value of equipment lost in the hurricane. Therefore, no gain was recognized in 2006. Subsequent to September 30, 2006, additional proceeds of $0.3 million were received and additional claims have been submitted. Capital costs to rebuild the rig are capitalized and depreciated in accordance with the accounting policy described in Critical Accounting Policies and Estimates. Because the rig is still under repair, the Company is unable to estimate the total amount of the gain or the periods in which the gain will be recognized. 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 6 A N D 2 0 0 5 INTERNATIONAL OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment 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 2006 2005 % Change (in thousands, except operating statistics) $252,792 172,606 3,498 19,512 $ 57,176 8,812 $ 23,404 $ 14,806 $ 8,598 27 90% $177,480 135,837 2,563 20,107 $ 18,973 7,491 $ 19,332 $ 14,039 $ 5,293 26 77% 42.4% 27.1 36.5 (3.0) 201.4 17.6% 21.1 5.5 62.4 3.8 16.9 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. Segment operating income for the Company’s international operations increased 201.4 percent from 2005 to 2006 due to higher rig activity and dayrates. Rig utilization for international operations averaged 90 percent in 2006, compared with 77 percent in 2005. During 2006, one new FlexRig was added to the international segment rig fleet. 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 6 A N D 2 0 0 5 REAL ESTATE Operating revenues Direct operating expenses Depreciation Segment operating income 2006 2005 % Change (in thousands) $10,379 3,524 2,444 $ 4,411 $10,688 3,622 2,352 $ 4,714 (2.9)% (2.7) 3.9 (6.4) Segment operating income in the Company’s Real Estate division decreased 6.4 percent from 2005 to 2006. The segment experienced decreases in reimbursements associated with property taxes and 40 increases in depreciation due to capital expenditures for leasehold and building improvements. 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. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment 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 segment 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 increase in margins continued during 2005, as crude oil and natural gas prices improved. Rig utilization increased to 94 percent in 2005 from 87 percent in 2004. The increase in utilization was a result of higher rig activity. Average rig expense per day increased 5 percent as the demand for drilling services tightened, putting pressure on both material costs and labor. The total number of rigs available at September 30, 2005 was 91 compared to 87 rigs at September 30, 2004. The increase was 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 41 in November 2004. Depreciation in 2005 increased 6.5 percent from 2004 due to the increase in available rigs. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 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 Segment 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. Segment 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, segment operating income would have been $15.9 million for 2004. Lower depreciation expense in 2005 was a result of the asset impairment. Segment operating income (loss), as reported Asset impairment charge Segment 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 segment operating income (loss) for the offshore platform segment for fiscal 2005 and 2004, which is provided to assist with yearly comparisons. 42 Segment 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. Financial performance during 2004 was hindered by continued softness in the offshore platform rig market which kept rig utilization 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. 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 Segment 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, the effects of management contracts, or the effect of currency revaluation expense. Segment 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 to 54 percent in 2004. Despite the 43 increase in operating income and rig activity, rig margins for international operations decreased slightly in 2005. The decrease is attributable to higher labor costs. 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 Segment operating income 2005 2004 % Change (in thousands) $10,688 3,622 2,352 $ 4,714 $10,015 4,564 2,253 $ 3,198 6.7% (20.6) 4.4 47.4 Segment operating income increased by 47.4 percent from 2004 to 2005 in the Company’s Real Estate division. 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. 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 was $528.9 million in 2006, $86.8 million in 2005, and $90.2 million in 2004. Net cash provided from operating activities for those same periods was $296.4 million in 2006, $212.2 million in 2005 and $136.6 million in 2004. The Company’s 2007 capital spending estimate is approximately $750 million, an increase from the budgeted $500 million in 2006, due to continued construction of new FlexRigs. Historically, the Company has financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, the Company 44 will either borrow from an available unsecured line of credit or, if market conditions are favorable, sell portfolio securities. Likewise, if the Company is generating excess cash flows, the Company may invest in additional portfolio securities or short-term investments. In 2006, the Company made portfolio security investments of $8.6 million. The following table reconciles purchases of portfolio securities to purchases of investments shown in the Consolidated Statements of Cash Flows in the Company’s Consolidated Financial Statements: Purchase of portfolio securities Purchase of short-term investments Purchase of investments 2006 $ 8,592 139,848 $148,440 2005 (in thousands) $ 3,000 2,000 $ 5,000 2004 $ $ — — — The Company manages a portfolio of marketable securities that, at the close of 2006, had a market value of $336.1 million. The Company’s investments in Atwood Oceanics, Inc. (‘‘Atwood’’) and Schlumberger, Ltd. made up almost 93 percent of the portfolio’s market value on September 30, 2006. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding the Company’s equity-method investment in Atwood and investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the Company’s balance sheet for each reporting period. The Company currently owns 4,000,000 shares or approximately 12.9 percent of the outstanding shares of Atwood. The Company generated cash proceeds from the sale of portfolio securities of $28.2 million in 2006, $46.7 million in 2005, and $30.9 million in 2004. 45 The following table reconciles cash proceeds from the sale of portfolio securities stated above to proceeds from sale of investments shown in the Consolidated Statements of Cash Flows in the Company’s Consolidated Financial Statements: 2006 Proceeds from the sale of portfolio securities $ 28,245 Sales with a trade date in current fiscal year but cash received in subsequent fiscal year Proceeds from the sale of short-term investments Proceeds from sale of investments per Consolidated (6,093) 91,563 2005 (in thousands) $ 46,700 16,839 2,000 2004 $ 30,872 (16,839) — Statements of Cash Flows $113,715 $ 65,539 $ 14,033 In 2006, proceeds were primarily from the sale of 230,000 shares of Schlumberger, Ltd. Proceeds were primarily used to repurchase shares of Company common stock and to fund capital expenditures. In 2005, proceeds were primarily from the sale of 1,000,000 shares of Atwood Oceanics, Inc. (Atwood), the Company’s equity affiliate. In July 2004, Atwood filed a Registration Statement covering all 3,000,000 shares of Atwood stock owned by the Company. On October 19, 2004, Atwood completed a secondary public offering of shares in which the Company sold 1,000,000 of its Atwood shares and received $45.6 million. The proceeds were invested in cash equivalent securities and were subsequently used to meet the Company’s capital expenditure needs. In 2004, proceeds were primarily from the sale of 250,000 shares of Schlumberger, 140,000 shares of Conoco-Phillips and various smaller investments. The proceeds were used for operations. The Company has historically been a long-term holder of investment securities. However, circumstances may arise such as significant 46 capital spending requirements, the opportunity to repurchase Company common stock or the above referenced Atwood offering that result in security sales that were not previously contemplated. During 2006, the Company purchased 1,325,200 of Company common stock at an aggregate cost of $30.2 million. Subsequent to September 30, 2006, the Company sold 500,000 shares of Schlumberger stock. The proceeds of approximately $30.2 million were used to repurchase 681,900 shares of Company common stock for approximately $15.9 million in October 2006 and funding capital expenditures. The Company’s proceeds from asset sales totaled $11.8 million in 2006, $29.0 million in 2005 and $7.9 million in 2004. In 2006, one U.S. land rig was sold generating $4.8 million in proceeds. Income from asset sales in 2006 totaled $7.5 million. In 2005, the Company sold two large domestic land rigs which generated a gain of approximately $9.0 million and proceeds of approximately $23.3 million. The rigs sold in 2006 and 2005 were idle at the time of the sales and, with the Company’s emphasis on FlexRig technology, the Company took advantage of the opportunity to sell the conventional rigs. In 2006 and 2005, the Company also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business. In 2004, a damaged mast on a rig in the international segment was sold generating a gain of approximately $1.7 million and proceeds of approximately $2.4 million. Additionally, undeveloped land owned by the Company’s Real Estate Division was sold to developers in 2004 with proceeds of approximately $1.1 million. In August 2006, the Company signed an option agreement to sell two U.S. offshore rigs. The net book value of the two rigs at 47 September 30, 2006 was $4.2 million and has been classified as ‘‘Assets held for sale’’ on the Company’s September 30, 2006 Consolidated Balance Sheet. In September 2006, the Company received $2.0 million from the optionee for exclusive rights to purchase the rigs. The $2.0 million is classified in current liabilities in the Consolidated Balance Sheet at September 30, 2006. An additional $6.0 million was received in October 2006 to exercise the extended option term. If the purchase option is exercised, the transaction will close in the second quarter of fiscal 2007. These two rigs are currently idle. During fiscal 2005 and fiscal 2006, the Company announced contracts to build and operate 66 new FlexRig3s and FlexRigs4s for 16 exploration and production companies. Subsequent to September 30, 2006, the Company announced that agreements had been reached with three exploration and production companies to operate an additional seven new FlexRigs bringing the total of the new rigs to 73. Each agreement, with the exception of one, has at least a three-year commitment by the operator under a minimum fixed contract. The drilling services are performed on a daywork contract basis. During fiscal 2006, 24 rigs were completed for delivery, and 21 of the 24 rigs began field operations by September 30, 2006. The remaining rigs are expected to be completed by the end of calendar 2007. Labor and equipment shortages have resulted in construction delays and increased costs compared to initial schedules and original cost estimates. Labor cost increases and labor shortages in both fabrication and rig-up services were due in large part to Hurricane Rita that hit south Texas in 2005, causing major skilled labor disruptions and significantly affecting one of the Company’s key fabricators of rig 48 components. Delivery schedules of the new rigs were pushed back to such a degree that late-delivery contractual liquidated damage payments were incurred and are expected to be incurred for most of the remaining rigs. However, the incurred and projected liquidated damage payments had, and are expected to have, minimal impact on revenues and margins. Although prices for components increased dramatically, the Company was able to secure favorable prices on a large amount of the equipment through advanced ordering and purchasing. The level of capital investment estimated for the construction of the 66 rigs increased by an average of approximately 16 percent per rig from the original estimate. The Company expects these increased capital costs to have a relatively small impact on the Company’s future earnings through incremental depreciation. The total estimated construction cost of all 73 rigs is currently $1.1 billion. Approximately $400 million was incurred in fiscal 2006 and approximately $600 million is expected to be incurred in fiscal 2007. 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 6.45 percent. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. On September 30, 2006, the Company had a committed unsecured line of credit totaling $50 million, with no money drawn and letters of credit totaling $16.4 million outstanding against the line. Borrowings against the line of credit bear interest at the London Interbank Bank Offered Rate (LIBOR) plus .875 percent to 1.125 percent or prime minus 1.75 percent to prime minus 1.50 percent. The spread over LIBOR or the prime rate depends on 49 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. At September 30, 2006, the Company was in compliance with all debt covenants. Subsequent to September 30, 2006, the Company entered into negotiations with a multi-bank syndicate for a five year, $400 million senior unsecured credit facility. The Company anticipates that the majority of all of the borrowings over the life of the new facility will accrue interest at a spread over LIBOR. The Company will also pay a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee will be determined according to a scale based on the ratio of the Company’s total debt to total capitalization. The LIBOR spread is expected to range from .30 percent to .45 percent depending on the ratio. Based on the ratio at the close of the fiscal year, the LIBOR spread on borrowings would be .35 percent and the commitment fee would be .075 percent per annum. Financial covenants in the facility are expected to restrict the Company to a total debt to total capitalization ratio of less than 50 percent and earnings before interest, taxes, depreciation, and amortization must be a minimum of three times consolidated interest expense on a rolling 12 month basis. The new facility is expected to contain additional terms, conditions, and restrictions that the Company believes are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. The closing of this facility is expected to occur in December 2006. At closing, the Company anticipates transferring two letters of credit totaling $20.9 million to the facility. 50 In conjunction with the $400 million senior unsecured credit facility, the Company began negotiations with a single bank to amend and restate the current unsecured line of credit from $50 million to $5 million. Pricing on the amended line of credit is expected to be prime minus 1.75 percent. The covenants and other terms and conditions are expected to be similar to the aforementioned senior credit facility except that there is no commitment fee. The closing for this line of credit is expected to occur in December 2006. After closing, the Company plans to have one letter of credit outstanding against this line and total remaining availability will be $4.9 million. As of September 30, 2006, the Company had four outstanding, unsecured notes payable to a bank totaling $3.7 million denominated in a foreign currency. The interest rate of the notes was 13 percent with a 60 day maturity. Subsequent to September 30, 2006, additional amounts totaling $12.3 million were borrowed with interest rates ranging from 12 percent to 16 percent and one note outstanding at September 30, 2006 for $1.2 million was paid. Current cash, short-term investments and cash provided from operating activities, together with funds available under the new credit facilities, are anticipated to be sufficient to meet the Company’s operating cash requirements and estimated capital expenditures, including rig construction, for fiscal 2007. Current ratios for September 30, 2006 and 2005 were 1.6 and 5.6, respectively. The decrease in current ratio is primarily due to a reduction in cash and cash equivalents and an increase in accounts payable and the current portion of long-term debt. These changes are due primarily to the FlexRig construction. The debt to total capitalization ratio was 14 percent and 17 percent at September 30, 2006 and 2005, respectively. 51 During 2006, the Company paid a dividend of $0.17 per share, or a total of $18.1 million, representing the 34th 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, 2006 Number of Shares Cost Basis Market Value Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total (in thousands, except share amounts) 4,000,000 2,150,000 $58,256 17,077 14,706 $90,039 $179,880 133,365 22,873 $336,118 M AT E R I A L C O M M I T M E N T S The Company has no off balance sheet arrangements other than operating leases discussed below. The Company’s contractual obligations as of September 30, 2006, are summarized in the table below: Payments Due By Year Total 2007 2008 2009 2010 2011 After 2011 $200,000 $ 25,000 $ — $25,000 $ — $ — $150,000 (in thousands) Long-term debt (a) Operating leases (b) Purchase obligations (b) 313,212 313,212 — — 8,637 3,694 2,726 1,715 502 — — — — — Total Contractual Obligations $521,849 $341,906 $2,726 $26,715 $502 $ — $150,000 (a) See Note 3 ‘‘Notes Payable and Long-term Debt’’ to the Company’s Consolidated Financial Statements. (b) See Note 14 ‘‘Commitments and Contingencies’’ to the Company’s Consolidated Financial Statements. The above table does not include obligations for the Company’s pension plan, for which the recorded liability at September 30, 2006 is $20.9 million. In 2006, the Company contributed $4.4 million to the plan. Based on current information available from plan actuaries, the Company does not anticipate contributions to the plan will be required in 2007. However, the Company does expect to make discretionary contributions to fund distributions of approximately 52 $3.0 million in 2007. Future contributions beyond 2007 are difficult to estimate due to multiple variables involved. 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. Depreciation is determined considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in 53 operations or technology or market conditions, could occur that would materially affect the Company’s estimates and assumptions related to depreciation. Management believes that these estimates have been materially accurate in the past. For the years presented in this report, no significant changes were made to the Company’s useful lives or salvage values, other than reflected in the 2004 impairment of certain offshore equipment. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in 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 utilization, 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 liability, employer’s liability, and auto liabilities. Generally, deductibles are $1.0 million or $2.0 million per occurrence depending on whether a 54 claim occurs inside or outside of the United States. Insurance is also purchased on rig properties and deductibles are typically $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 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. 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 the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. The Company anticipates pension expense in 2007 to decrease from 2006. 55 Revenues and costs on daywork contracts are recognized daily as the work progresses. For certain contracts, payments are received that are contractually designated for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. N E W A C C O U N T I N G S TA N D A R D Effective October 1, 2005, the Company began recording compensation expense associated with stock options in accordance with SFAS No. 123(R), ‘‘Share-Based Payment’’. Prior to October 1, 2005, the Company accounted for stock-based compensation related to stock options under the recognition and measurement principles of Accounting Principles Board Opinion No. 25. Therefore, the Company measured compensation expense for its stock option plan using the intrinsic value method, that is, as the excess, if any, of the fair market value of the Company’s stock at the grant date over the amount required to be paid to acquire the stock, and provided the disclosures required by SFAS No. 123. The Company has adopted the modified prospective transition method provided under SFAS No. 123(R) and, as a result, has not retroactively adjusted results from prior periods. Under this transition method, compensation expense associated with stock options recognized in fiscal year 2006 includes: 1) expense related to the remaining unvested portion of all stock option awards granted prior to October 1, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123; and 2) expense related to all stock 56 option awards granted subsequent to October 1, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The Company recorded pre-tax stock-based compensation expense of $9.8 million in 2006. Stock-based compensation includes $8.7 million related to stock options and $1.1 million related to restricted stock. During 2006, the Company expensed $2.8 million due to the Company accelerating the vesting of share options held by a senior executive who retired. At September 30, 2006, unrecognized compensation cost related to unvested restricted stock options was $5.2 million. The cost is expected to be recognized over a weighted- average period of 4.1 years. Note 6 in the notes to the consolidated financial statements provides additional information and details pertaining to stock-based compensation. In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Benefit Plans (SFAS 158). SFAS 158 requires companies to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position. This statement is effective for financial statements as of the end of fiscal years ending after December 15, 2006, or fiscal 2007 for the Company. As discussed in Note 10 in the notes to the consolidated financial statements, the Company’s pension plan was frozen on September 30, 2006. As a result of the plan being frozen, the Company has effectively reflected the funded status of the plan in the Consolidated Balance Sheet; therefore, SFAS 158 will have no impact on the consolidated financial statements. 57 In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating SFAS No. 157 to determine the impact, if any, on its financial statements. In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108). SAB 108 considers the effects of prior year misstatements when quantifying misstatements in current year financial statements. It is effective for fiscal years ending after November 15, 2006. The Company does not believe the adoption of SAB 108 will have a material impact on the consolidated financial statements. In June, 2006, The Financial Accounting Standards Board (‘‘FASB’’) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently assessing the impact of this Interpretation on the financial statements. 58 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 operations in several South American countries and Africa. 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 60 percent of the Company’s billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar. On October 1, 2003, in compliance with applicable regulations, the Company submitted a request to the Venezuelan government seeking permission to convert existing bolivar balances into U.S. dollars. In January 2004, the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars and the remittance of $8.8 million U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S. based parent. This was the first dividend remitted under the new regulation. On January 16, 2006, a dividend of $6.5 million U.S. dollars was paid to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation has been reduced by these amounts. On August 18, 2006, 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. The Company anticipates the dividend to be approximately $9.3 million. 59 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 per U.S. dollar 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. Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Even though Venezuela continues to operate under the exchange controls in place and the Venezuelan bolivar exchange rate has remained fixed at 2150 bolivares to one U.S. dollar since the devaluation in March, 2005, the exact amount and timing of devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2007 activity levels are similar to fiscal 2006 and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.5 million to $2.8 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 to receiving payments in bolivares and thus increase bolivar cash balances and exposure to devaluation. Credit Risk The Company derives its revenue in Venezuela from Petr´oleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company. At September 30, 2006, the Company had a net receivable from PDVSA of $45.4 million of which $16.2 million was 90 days old or older. At December 1, 2006, such receivable balance 60 had increased to approximately $66 million, of which approximately $40 million was 90 days old or older. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than that of other customers in international countries in which the Company has drilling operations. In order to establish a source of local currency to meet current obligations in Venezuela bolivares, the Company is borrowing in the form of short-term notes from two local banks in Venezuela at the market interest rates designated by the banks. 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 of 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. The prices for drilling rig components have experienced increases in the last year. While these materials have generally been available to 61 the Company at acceptable prices, there is no assurance the prices will not vary significantly in the future. The Company attempts to secure favorable prices through advanced ordering and purchasing. Additionally, future fluctuations in market conditions causing increased prices in materials and supplies could impact future operating costs adversely. 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 credit arrangements expected to be entered into subsequent to year-end will have floating interest rates. The Company’s entire debt portfolio at September 30, 2006 was in fixed-rate debt. The Company has reduced the impact of fluctuations in interest rates by maintaining a portion of its debt portfolio in fixed-rate debt. The following tables provide information as of September 30, 2006 and 2005 about the Company’s interest rate risk sensitive instruments: 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 6 (dollars in thousands) 2007 2008 2009 2010 2011 After 2011 Fair Value Total @ 9/30/06 Fixed Rate Long-term Debt $25,000 $ — $25,000 $ — $ — $150,000 $200,000 $209,000 Average Interest Rate 5.5% — 5.9% — — 6.5% 6.4% Fixed Rate Notes Payable (a) $ 3,721 Average Interest Rate 13.0% (a) Denominated in a foreign currency $ 3,721 $ 3,721 13.0% 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 (dollars in thousands) 2006 2007 2008 2009 2010 After 2010 Fair Value Total @ 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% 62 Equity Price Risk On September 30, 2006, the Company had a portfolio of available-for-sale securities with a total market value of $336.1 million. The total market value of the portfolio of securities was $293.4 million at September 30, 2005. 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, 2006. Although the Company sold portions of its positions in Schlumberger in 2004 and 2006, and Atwood in the first fiscal quarter of fiscal 2005, the Company makes no specific plans to sell securities, but rather sells 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. and investments in limited partnerships carried at cost, 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. 63 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, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2006. 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, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2006, 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, 2006, 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 7, 2006 expressed an unqualified opinion thereon. As discussed in Note 1 to the consolidated financial statements, in 2006 the Company changed its method of accounting for Stock-Based Compensation. E R N S T & Y O U N G L L P Tulsa, Oklahoma December 7, 2006 64 Consolidated Statements of Income Years Ended September 30, 2006 2005 2004 OPERATING REVENUES Drilling – U.S. Land Drilling – U.S. Offshore Drilling – International Real Estate OPERATING COSTS AND EXPENSES Operating costs, excluding depreciation Depreciation Asset impairment General and administrative Income from asset sales Operating income (loss) Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Income before income taxes and equity in income of affiliate Income tax provision Equity in income of affiliate net of income taxes 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. (in thousands, except per share amounts) $ 829,062 $527,637 $346,015 132,580 252,792 10,379 1,224,813 661,563 101,583 — 51,873 (7,492) 84,921 177,480 10,688 800,726 484,231 96,274 — 41,015 (13,550) 84,238 148,788 10,015 589,056 417,716 94,425 51,516 37,661 (5,377) 807,527 607,970 595,941 417,286 192,756 (6,885) 9,834 (6,644) 19,866 639 23,695 440,981 154,391 7,268 5,809 (12,642) 26,969 (235) 19,901 212,657 87,463 2,412 1,965 (12,695) 25,418 197 14,885 8,000 4,365 724 $ 293,858 $127,606 $ 4,359 $ $ 2.81 2.77 $ $ 1.25 1.23 $ $ 0.04 0.04 104,658 106,091 102,174 104,066 100,623 101,666 65 Consolidated Balance Sheets ASSETS CURRENT ASSETS: Cash and cash equivalents Short term investments September 30, 2006 2005 (in thousands) Accounts receivable, less reserve of $2,007 in 2006 and $1,791 in 2005 Inventories Deferred income taxes Assets held for sale Prepaid expenses and other Total current assets $ 33,853 $ 288,752 48,673 289,479 26,165 10,168 4,234 16,119 428,691 388 162,646 21,313 8,765 — 17,933 499,797 INVESTMENTS 218,309 178,452 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. 1,911,039 1,549,112 220,603 58,286 113,788 2,303,716 820,582 1,483,134 34,774 57,489 96,614 1,737,989 756,024 981,965 4,578 3,136 $2,134,712 $1,663,350 66 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, 2006 2005 (in thousands, except share data) CURRENT LIABILITIES: Notes payable Accounts payable Accrued liabilities Long-term debt due within one year Total current liabilities NONCURRENT LIABILITIES: Long-term debt Deferred income taxes Other Total noncurrent liabilities SHAREHOLDERS’ EQUITY: Common stock, $.10 par value, 160,000,000 shares authorized, 107,057,904 shares issued and outstanding Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Unearned compensation Accumulated other comprehensive income Less treasury stock, 3,188,760 shares in 2006 and 3,188,724 shares in 2005, at cost Total shareholders’ equity $ 3,721 $ — 138,750 97,077 25,000 264,548 175,000 269,919 43,353 488,272 44,854 44,627 — 89,481 200,000 246,975 47,656 494,631 10,706 10,706 — 135,500 1,215,127 — 69,645 — 106,944 939,380 (134) 47,544 1,430,978 1,104,440 49,086 1,381,892 25,202 1,079,238 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $2,134,712 $1,663,350 The accompanying notes are an integral part of these statements. 67 Consolidated Statements of Shareholders’ Equity Common Stock Shares Amount Additional Paid-In Capital Retained Earnings Unearned Compensation Accumulated Other Comprehensive Income (Loss) Shares Treasury Stock Amount Total Balance, September 30, 2003 107,058 $10,706 $ 77,949 $ 840,776 $(10) $33,668 6,777 $(45,838) $ 917,251 (in thousands, except per share amounts) Comprehensive Income: Net Income Other comprehensive income: Unrealized gains on available-for- sale securities, net Derivatives instruments Amortization, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Cash dividends ($.16125 per share) Exercise of stock options Tax benefit of stock-based awards Amortization of deferred compensation Balance, September 30, 2004 Comprehensive Income: Net Income Other comprehensive income (loss): Unrealized gains on available-for- sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Capital adjustment of equity investee Stock issued under Restricted Stock Award Plan Cash dividends ($.165 per share) Exercise of stock options Tax benefit of stock-based awards Amortization of deferred compensation Balance, September 30, 2005 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 Reversal of unearned compensation upon adoption of SFAS 123(R) Cash dividends ($.1725 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $10.2 million Repurchase of common stock Stock-based compensation Balance, September 30, 2006 4,359 3,721 72 (1,209) (16,372) 813 1,351 (610) 4,114 107,058 10,706 80,113 828,763 10 — 36,252 6,167 (41,724) 127,606 2,682 93 8,903 15,153 (16,989) 107,058 10,706 106,944 939,380 293,858 14,708 (3,416) (160) 26 (134) (10) (2,968) 47,544 3,189 17,591 4,510 67 16,455 — (16,989) 25,358 15,153 26 (25,202) 1,079,238 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 2,682 293,858 17,591 4,510 22,101 315,959 — (18,111) 12,372 134 10 (68) (18,111) (1,335) 6,353 (66) 6,019 12,851 9,752 107,058 $10,706 $135,500 $1,215,127 $ — $69,645 1,325 (30,169) 12,851 (30,169) 9,752 3,189 $(49,086) $1,381,892 The accompanying notes are an integral part of these statements. 68 Consolidated Statements of Cash Flows Years Ended September 30, 2006 2005 2004 OPERATING ACTIVITIES: Net income Adjustments to reconcile income to net cash provided by operating activities: Depreciation Asset impairment charge Equity in income of affiliate before income taxes Stock-based 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 (in thousands) $ 293,858 $127,606 $ 4,359 101,583 — (11,723) 9,752 (19,730) — (7,492) 3,504 (737) 96,274 — (3,891) 26 94,425 51,516 (1,168) 10 (26,969) (22,766) — (13,550) 38,014 (349) (120,740) (46,223) (4,852) 372 (11,064) 55,112 4,490 4,057 (487) 1,451 8,517 12,736 16,557 2,526 (2,521) (5,377) 5,934 (98) (25,335) 1,707 24,142 (378) 2,870 2,323 6,997 Net cash provided by operating activities 296,390 212,238 136,640 INVESTING ACTIVITIES: Capital expenditures Proceeds from asset sales Insurance proceeds from involuntary conversion Purchase of investments Proceeds from sale of investments Net cash provided by (used in) investing activities FINANCING ACTIVITIES: Repurchase of common stock Increase (decrease) in short-term notes Increase in bank overdraft Dividends paid Proceeds from exercise of stock options Excess Tax benefit from stock based compensation 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. (528,905) 11,778 2,970 (148,440) 113,715 (548,882) (28,407) 3,721 17,430 (17,712) 12,372 10,189 (2,407) (254,899) 288,752 (86,805) 28,992 — (5,000) 65,539 2,726 — — — (16,866) 25,358 — 8,492 223,456 65,296 (90,212) 7,941 — — 14,033 (68,238) — (30,000) — (16,222) 4,927 — (41,295) 27,107 38,189 $ 33,853 $288,752 $ 65,296 69 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. Specifically, ‘‘Income from asset sales’’ for the years ended September 30, 2005 and 2004 has been reclassified to be included in operating income. All prior period common stock and applicable share and per share amounts have been retroactively adjusted to reflect a 2-for-1 split of the Company’s common stock effective June 26, 2006. FOREIGN CURRENCIES The Company’s functional currency for all its foreign subsidiaries is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the year. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars are included in direct operating costs. Gains and losses resulting from foreign currency transactions are also included in current results of operations. Aggregate foreign currency remeasurement and transaction losses included in direct operating costs totaled $0.3 million, $0.8 million and $2.2 million in 2006, 2005, and 2004 respectively. USE OF ESTIMATES The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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. 70 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 2006, 2005, and 2004 was $6.1 million, $.3 million, and $.5 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 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 equivalents consist of investments in short-term, highly liquid securities having original maturities of three months or less, which are made as part of the Company’s cash management activity. The carrying values of these assets approximate their fair market values. The Company primarily utilizes a cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts that funds are moved to, and several ‘‘zero-balance’’ disbursement accounts for funding payroll and accounts payable. As a result of the Company’s cash management system, checks issued, but not presented to the banks for payment, may create negative book cash balances. Checks outstanding in excess of related book cash balances totaling approximately $17.4 million at September 30, 2006 are included in accounts payable. RESTRICTED CASH AND CASH EQUIVALENTS The Company had restricted cash and cash equivalents of $4.3 million and $4.2 million at September 30, 2006 and 2005, respectively. All restricted cash is for the purpose of potential insurance claims in the Company’s wholly-owned captive insurance company. Of the total at September 30, 2006, $2.0 million is from the initial capitalization of the captive and management has elected to restrict an additional $2.3 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 2006 $2,273 $2,000 2005 $2,195 $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 of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed. For certain contracts, the Company receives payments 71 contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization are deferred and recognized on a straight line basis 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: Years Ended September 30, Minimum rents Overage and percentage rents 2006 $8,538 $1,219 2005 (in thousands) $7,606 $1,162 2004 $7,490 $1,207 At September 30, 2006, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2007 2008 2009 2010 2011 Thereafter Total Amount $ 7,265 5,767 4,333 3,617 2,696 3,744 $27,422 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2006 and 2005, the cost and accumulated depreciation for real estate properties were as follows: September 30, Real estate properties Accumulated depreciation 2006 2005 $58,286 (31,664) $26,622 $57,489 (29,626) $27,863 72 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, $0.02 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 the 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 public offering of Atwood. The sale generated $15.9 million ($0.15 per diluted share) of net income in fiscal 2005. In March 2006, Atwood had a two-for-one stock split. The Company currently owns 4,000,000 shares of Atwood which represents approximately 12.9 percent of Atwood. The Company 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 $179.9 million and $168.4 million at September 30, 2006 and 2005, respectively. Retained earnings at September 30, 2006 and 2005 includes approximately $31.6 million and $24.3 million, respectively, of undistributed earnings of Atwood. Summarized financial information of Atwood is as follows: September 30, Gross revenues Costs and expenses Net income 2006 $276,625 190,503 $ 86,122 2005 (in thousands) $176,156 149,785 $ 26,371 Helmerich & Payne, Inc.’s equity in net income, net of income taxes $ 7,268 $ 2,412 Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity $147,673 446,156 61,365 73,570 $458,894 $ 93,283 403,641 56,159 78,268 $362,497 2004 $163,454 155,867 $ $ 7,587 724 $ 92,966 405,970 60,053 167,294 $271,589 Helmerich & Payne, Inc.’s investment $ 58,256 $ 46,533 $ 57,824 73 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. STOCK-BASED COMPENSATION Effective October 1, 2005, the Company began recording compensation expense associated with stock options in accordance with SFAS No. 123(R), ‘‘Share-Based Payment’’. Prior to October 1, 2005, the Company accounted for stock-based compensation related to stock options under the recognition and measurement principles of Accounting Principles Board Opinion No. 25. Therefore, the Company measured compensation expense for its stock option plan using the intrinsic value method, that is, as the excess, if any, of the fair market value of the Company’s stock at the grant date over the amount required to be paid to acquire the stock, and provided the disclosures required by SFAS No. 123. The Company adopted the modified prospective transition method provided under SFAS No. 123(R), and as a result, has not retroactively adjusted results from prior periods. Under this transition method, compensation expense associated with stock options recognized in fiscal year 2006 includes: 1) expense related to the remaining unvested portion of all stock option awards granted prior to October 1, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123; and 2) expense related to all stock option awards granted subsequent to October 1, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The adoption of SFAS No. 123(R) also resulted in certain changes to the Company’s accounting for its restricted stock awards, which is discussed in Note 6 in more detail. 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 STANDARDS In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Benefit Plans (SFAS 158). SFAS 158 requires companies to recognize the overfunded or 74 underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position. This statement is effective for financial statements as of the end of fiscal years ending after December 15, 2006. As discussed further in Note 10, the Company’s pension plan was frozen on September 30, 2006. As a result of the plan being frozen, the Company has effectively reflected the funded status of the plan in the Consolidated Balance Sheets; therefore, SFAS 158 will have no impact on the consolidated financial statements. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating SFAS No. 157 to determine the impact, if any, on its financial statements. In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108). SAB 108 considers the effects of prior year misstatements when quantifying misstatements in current year financial statements. It is effective for fiscal years ending after November 15, 2006. The Company does not believe the adoption of SAB 108 will have a material impact on the consolidated financial statements. In June, 2006, The Financial Accounting Standards Board (‘‘FASB’’) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently assessing the impact of this Interpretation on the financial statements. 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 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 segment was reduced by approximately $1.5 million in fiscal year 2005. 75 NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 2006 and 2005, the Company had $200 million in unsecured long-term debt outstanding at fixed rates and maturities as summarized in the following table: Maturity Date Interest Rate August 15, 2007 August 15, 2009 August 15, 2012 August 15, 2014 5.51% 5.91% 6.46% 6.56% Less long-term debt due within one year Long-term debt September 30, 2006 $ 25,000,000 25,000,000 75,000,000 75,000,000 $200,000,000 (25,000,000) $175,000,000 2005 $ 25,000,000 25,000,000 75,000,000 75,000,000 $200,000,000 — $200,000,000 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, 2006, the Company had a committed unsecured line of credit totaling $50 million. Letters of credit totaling $16.4 million were outstanding against the line, leaving $33.6 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. Borrowings against the line of credit bear interest at the London Interbank Bank Offered Rate (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, 2006 and 2005, no balances were outstanding under the line of credit. The revolving credit commitment expires July 10, 2007, however, subsequent to year end, this line of credit was cancelled by the Company and a new facility was obtained as discussed below. At September 30, 2006, the Company was in compliance with all debt covenants. As of September 30, 2006, the Company had four outstanding, unsecured notes payable to a bank totaling $3.7 million denominated in a foreign currency. The interest rate of the notes was 13 percent with a 60 day maturity. Subsequent to September 30, 2006, additional amounts totaling $12.3 million were borrowed with interest rates ranging from 12 percent to 16 percent and one note outstanding at September 30, 2006 for $1.2 million was paid. Subsequent to September 30, 2006, the Company entered into negotiations with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility. The Company anticipates that the majority of all of the borrowings over the life of the new facility will accrue interest at a spread over LIBOR. The Company will also pay a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is expected to be determined according to a scale based on a ratio of the Company’s total debt to total capitalization. The LIBOR spread is expected to range from .30 percent to .45 percent depending 76 on the ratios. Based on the ratio at the close of the fiscal year, the LIBOR spread on borrowings would be .35 percent and the commitment fee would be .075 percent per annum. Financial covenants in the facility are expected to restrict the Company to a total debt to total capitalization ratio of less than 50 percent and earnings before interest, taxes, depreciation, and amortization must be a minimum of consolidated interest expense on a rolling 12 month basis. The new facility is expected to contain additional terms, conditions, and restrictions that the Company believes are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. The closing of this facility is expected to occur in December 2006. At closing, the Company anticipates transferring two letters of credit totaling $20.9 million to the facility. In conjunction with the $400 million senior unsecured credit facility, the Company began negotiations with a single bank to amend and restate the current unsecured line of credit from $50 million to $5 million. Pricing on the amended line of credit is expected to be prime minus 1.75 percent. The covenants and other terms and conditions are expected to be similar to the aforementioned senior credit facility except that there is no commitment fee. The closing for this line of credit is expected to occur in December 2006. After closing, the Company plans to have one letter of credit outstanding against this line and total remaining availability will be $4.9 million. 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 2006 $136,370 4,304 10,213 150,887 10,252 (7,776) 1,028 3,504 $154,391 2005 (in thousands) $39,139 8,185 2,125 49,449 31,573 4,863 1,578 38,014 $87,463 2004 $(5,997) 4,622 (194) (1,569) 4,037 1,902 (5) 5,934 $ 4,365 The amounts of domestic and foreign income before income taxes and equity in income of affiliate are as follows: Years Ended September 30, Domestic Foreign 2005 (in thousands) $195,978 16,679 $212,657 2004 $ (2,565) 10,565 $ 8,000 2006 $389,595 51,386 $440,981 77 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. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets assumes, based on estimates and assumptions, that the Company will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances will be recorded against the deferred tax assets resulting in additional income tax expense in the future. 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 Self-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 2006 2005 (in thousands) $220,851 48,593 19,350 51 288,845 8,441 3,384 33,029 — 17,260 9 62,123 33,029 29,094 $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 $259,751 $238,210 Reclassifications have been made to the fiscal 2005 balances for certain components of deferred tax assets and liabilities in order to conform to the current year’s presentation. The change in the Company’s net deferred tax assets and liabilities are impacted by foreign currency remeasurement. As of September 30, 2006 the Company had state and foreign net operating loss carryforwards for income tax purposes of $16.5 million and $3.4 million, respectively, and foreign tax credit carryforwards of approximately $30.7 million which will expire in years 2010 through 2015. The valuation allowance is primarily attributable to state and foreign net operating loss carryforwards and foreign tax credit carryforwards for which it is more likely than not that these will not be utilized. 78 Effective income tax rates as compared to the U.S Federal income tax rate are as follows: Years Ended September 30, U.S. Federal income tax rate Effect of foreign taxes State income taxes Other Effective income tax rate NOTE 5 SHAREHOLDERS’ EQUITY 2006 35% (1) 1 — 35% 2005 35% 3 3 2 43% 2004 35% 18 — — 53% On March 1, 2006, the Company’s Board of Directors approved a two-for-one stock split on its common stock, subject to shareholder approval of an amendment to the Company’s Restated Certificate of Incorporation to increase the number of authorized common shares of the Company. On June 23, 2006, the Company’s shareholders approved the amendment. As a result, the split was paid in the form of a share distribution on July 7, 2006 to the shareholders of record on June 26, 2006. The Company retained the current par value of $.10 per share for all shares of common stock. All references in the financial statements to the number of shares outstanding, per share amounts, and stock option data of the Company’s common stock have been restated to reflect the effect of the stock split for all periods presented. On September 30, 2006, the Company had 103,869,144 outstanding common stock purchase rights (‘‘Rights’’) pursuant to the terms of the Rights Agreement dated January 8, 1996, as amended by Amendment No. 1 dated December 8, 2005. As adjusted for the two-for-one stock splits in fiscals 1998 and 2006, and as long as the rights are not separately transferable, one-half right attaches to each share of the Company’s common stock. Under the terms of the Rights Agreement each Right entitled the holder thereof to purchase from the Company one full 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 $250 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, 2016. 79 NOTE 6 STOCK-BASED COMPENSATION The Company has several plans providing for stock based awards to employees and to non-employee directors. The plans permit the granting of various types of awards including stock options and restricted stock. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire ten years after grant. In March 2001, the Company adopted the 2000 Stock Incentive Plan (the ‘‘Stock Incentive Plan’’). The Stock Incentive Plan was effective December 6, 2000 and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options for up to 6,000,000 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 900,000 shares of the total authorized may be granted to participants as restricted stock awards. All share amounts have been adjusted to reflect a stock split that was effective June 26, 2006. Effective March 1, 2006, no additional common-stock based awards will be granted under the Stock Incentive Plan. On March 1, 2006, at the Annual Meeting of Stockholders, the 2005 Long-Term Incentive Plan was approved. The Plan, among other things, authorizes the Board of Directors to grant nonqualified and incentive stock options, restricted stock awards, stock appreciation rights and performance units to selected employees and to non-employee Directors. In fiscal 2006, no stock awards were granted from this plan. The Company has the right to satisfy option exercises from treasury shares and from authorized but unissued shares. During fiscal 2006, 1,325,200 shares were purchased at an aggregate cost of $30.2 million of which $1.8 million did not settle until after September 30, 2006. Subsequent to year end, the Company purchased 681,900 shares at an aggregate cost of $15.9 million. The Company may purchase additional shares if the share price is favorable. In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (Revised 2004), Share Based Payment (‘‘SFAS 123(R)’’). SFAS 123(R) is a revision of SFAS No. 123, as amended, Accounting for Stock-Based Compensation (‘‘SFAS 123’’), and supersedes Accounting Principles Board Opinion (‘‘APB’’) No. 25, Accounting for Stock Issued to Employees (‘‘APB 25’’). SFAS 123(R) eliminated the alternative to use the intrinsic value method of accounting that was provided in SFAS 123, which generally resulted in no compensation expense recorded in the financial statements related to the issuance of stock options with an exercise price that was equal to the award’s grant date fair value. SFAS 123(R) requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. SFAS 123(R) established fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value based measurement method in accounting for all share-based payment transactions with employees. In October 2005, the Company adopted SFAS 123(R) using a modified prospective application, as permitted under SFAS 123(R). Accordingly, prior period amounts have not been restated. Under this application, the Company is required to record compensation expense for all awards granted after the date of adoption and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. 80 Additionally, SFAS 123(R) requires that the benefits of the tax deduction in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under previously effective accounting principles generally accepted in the United States. The adoption of SFAS 123(R) also resulted in certain changes to the Company’s accounting for restricted stock awards, which is discussed below in more detail. In November 2005, the FASB issued FSP No. 123R-3 (‘‘FSP 123R-3’’), Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards, to provide an alternative transition election related to accounting for the tax effects of share-based awards to employees to the guidance provided in Paragraph 81 of SFAS 123(R). The guidance in FSP 123R-3 was effective on November 11, 2005. An entity may take up to one year from the later of its initial adoption of SFAS 123(R) or the effective date of FSP 123R-3 to evaluate its available transition alternatives and make its one-time election. Until and unless an entity elects the transition method described in FSP 123R-3, the entity should follow the transition method described in Paragraph 81 of SFAS 123(R). SFAS 123(R) requires an entity to calculate the pool of excess tax benefits available to absorb tax deficiencies recognized subsequent to adopting Statement 123(R) (termed the ‘‘APIC Pool’’). The Company is using the transition method as described in Paragraph 81 of SFAS 123(R). A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense and cash received from the exercise of stock options in fiscal 2006 is as follows (in thousands, except per share amounts): Compensation expense Stock options Restricted stock After-tax stock based compensation Per basic share Per diluted share Cash received from exercise of stock options $ 8,714 1,038 $ 9,752 $ 6,046 $ $ .06 .06 $12,372 Benefits of tax deductions in excess of recognized compensation cost of $10.2 million is reported as a financing cash flow in the Consolidated Condensed Statements of Cash Flow for fiscal 2006. In December 2005, the Company accelerated the vesting of share options held by a senior executive who retired. As a result of that modification, the Company recognized additional compensation expense of $2.8 million for the fiscal year ended September 30, 2006. STOCK OPTIONS Vesting requirements for stock options 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 81 December 3, 1997, began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years. Prior to adoption of SFAS 123(R), the Company used the Black-Scholes formula to estimate the value of stock options granted to employees. The Company continues to use this acceptable option valuation model following the adoption of SFAS 123(R). The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods. The following summarizes the weighted-average assumptions in the model. Risk-free interest rate Expected stock volatility Dividend yield Expected term (in years) 2006 4.5% 36.9% .5% 5.2 2005 4.2% 40.3% 1.0% 5.0 2004 3.7% 44.0% .8% 5.5 Risk-Free Interest Rate. The risk-free interest rate is based on the U.S. Treasury securities for the expected term of the option. Expected Volatility Rate. Expected volatilities are based on the daily closing price of the Company’s stock based upon historical experience over a period which approximates the expected term of the option. Expected Dividend Yield. The dividend yield is based on the Company’s current dividend yield. Expected Term. The expected term of the options granted represents the period of time that they are expected to be outstanding. The Company estimates the expected term of options granted based on historical experience with grants and exercises. The following summary reflects the stock option activity for the Company’s common stock and related information for 2006, 2005, and 2004 (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2006 2005 2004 Weighted-Average Exercise Price $12.29 29.68 12.25 18.56 $14.24 $11.74 Options 6,488 640 (1,483) (26) 5,619 3,847 4,000 Options 8,914 926 (3,222) (130) 6,488 4,054 1,510 Weighted-Average Exercise Price $11.02 16.01 9.79 13.61 $12.29 $11.37 Weighted-Average Exercise Price $10.71 12.09 8.08 12.69 $11.02 $10.31 Options 8,654 938 (610) (68) 8,914 5,994 2,316 82 The following table summarizes information about stock options at September 30, 2006 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $6.3975 to $9.4178 $11.3318 to $16.0100 $30.2375 $6.3975 to $30.2375 Options 894 4,119 606 5,619 Weighted-Average Remaining Life Weighted-Average Exercise Price 2.7 6.2 9.2 6.0 $ 8.00 $13.24 $30.24 $14.24 Options 894 2,941 12 3,847 Weighted-Average Exercise Price $ 8.00 $12.81 $30.24 $11.74 At September 30, 2006, the weighted-average remaining life of exercisable stock options was 5.03 years and the aggregate intrinsic value was $43.4 million with a weighted-average exercise price of $11.74 per share. The number of options expected to vest at September 30, 2006 was 5,596,678 with an aggregate intrinsic value of $49.5 million and a weighted-average exercise price of $14.18 per share. As of September 30, 2006, the unrecognized compensation cost related to the stock options was $9.2 million. That cost is expected to be recognized over a weighted-average period of 2.4 years. The weighted-average fair value of options granted during 2006, 2005 and 2004 was $11.40, $6.09 and $5.12, respectively. The total intrinsic value of options exercised during the 2006, 2005 and 2004 was $34.9 million, $41.3, and $3.8 million, respectively. The fair value of shares vested during fiscal 2006 was $9.1 million. Prior to October 1, 2005, stock-based awards were accounted for under APB 25 and related interpretations. Fixed plan common stock options generally did not result in compensation expense because the exercise price of the options issued by the Company was equal to the market price of the underlying stock on the date of grant. The following table illustrates the effect on the net income and earnings per share as if the Company 83 had applied the fair value recognition provisions of SFAS No. 123, ‘‘Accounting for Stock-Based Compensation’’: September 30, Net income, as reported 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 2005 2004 (thousands, except per share amounts) $127,606 $4,359 16 (3,563) $124,059 $ $ $ $ 1.25 1.21 1.23 1.19 6 (4,172) $ 193 $ 0.04 $ 0.00 $ 0.04 $ 0.00 RESTRICTED STOCK Restricted stock awards consist of the Company’s common stock and are time vested over three to five years. The Company recognizes compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards is determined based on the closing trading price of the Company’s shares on the grant date. As of September 30, 2006, there was $5.2 million of total unrecognized compensation cost related to unvested restricted stock options granted under the Plan. That cost is expected to be recognized over a weighted-average period of 4.1 years. Prior to the adoption of SFAS 123(R), unearned compensation related to restricted stock awards was classified as a separate component of stockholders’ equity. In accordance with the provisions of SFAS 123(R), on October 1, 2005, the balance in unearned compensation was reclassified to additional paid-in capital on the balance sheet. A summary of the status of the Company’s restricted stock awards as of September 30, 2006, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2006 and 2005 is as follows (in thousands): Outstanding at October 1, Granted Vested Forfeited/Expired Outstanding on September 30, 2006 Weighted-Average Grant Date Fair Value per Share $16.01 30.24 — — $29.57 2005 Weighted-Average Grant Date Fair Value per Share $ — 16.01 — — $16.01 Shares — 10 — — 10 Shares 10 203 — — 213 84 No restricted stock awards were granted during fiscal 2004 or outstanding at September 30, 2004. NOTE 7 EARNINGS PER SHARE The computation of basic earnings per share is based on the weighted average number of common shares outstanding during the period. The computation of diluted earnings per share reflects the potential dilution that would occur if stock options were exercised and the dilution from the issuance of restricted shares, computed using the treasury stock method. 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 and restricted stock Diluted weighted-average shares 2006 104,658 1,433 106,091 2005 (in thousands) 102,174 1,892 104,066 2004 100,623 1,043 101,666 At September 30, 2006, options to purchase 809,450 shares of common stock at a weighted-average price of $30.2375 were outstanding, but were not included in the computation of diluted earnings per share. Inclusion of these shares would be antidilutive. 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 2,055,360 shares of common stock at a weighted-average price of $13.92 were outstanding, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. NOTE 8 FINANCIAL INSTRUMENTS The Company had $200 million of long-term debt outstanding at September 30, 2006 which had an estimated fair value of $209 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. 85 The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1), investments in limited partnerships carried at cost and assets held in a Non-qualified Supplemental Savings Plan: Equity Securities: September 30, 2006 September 30, 2005 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $19,413 $30,937 $122,490 $ 94,000 $(115) $ — $141,788 $124,937 On an on-going basis, the Company evaluates the marketable equity securities to determine if a decline in fair market is other-than-temporary. If a decline in fair market value is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis established. In determining if an unrealized loss is other-than-temporary, the Company considers how long the market value of the investment has been below cost, how significant the decline in value is as a percentage of the original cost and the market in general and analyst recommendations. At September 30, 2006, one marketable equity security had a fair market value of $1.5 million which was less than the recorded cost. The security had been in a continuous loss position for approximately four months. The Company did not consider this unrealized loss to be other-than-temporary and, subsequent to year-end, the fair market value of the one equity security exceeded the cost basis. During the years ended September 30, 2006, 2005, and 2004, marketable equity available-for-sale securities with a fair value at the date of sale of $28.2 million, $46.7 million, and $30.9 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $19.8 million, $27.0 million, and $22.8 million, respectively, and the gross realized losses totaled $7 thousand in fiscal 2004. In fiscal 2006 and 2004, the Company had $0.1 million in gains related to non-monetary transactions. The investments in the limited partnerships carried at cost were approximately $12.4 million and $3.0 million at September 30, 2006 and 2005, respectively. The estimated fair value exceeded the cost of investments at September 30, 2006 and 2005 and, as such, the investments were not impaired. The assets held in a Non-qualified Supplemental Savings Plan are valued at fair market which totaled $5.9 million and $7.0 million at September 30, 2006 and 2005, respectively. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments. At September 30, 2006, the Company’s short-term investments consisted primarily of auction rate securities which are classified as available-for-sale. The interest or dividend rates on the Company’s auction rate securities are generally reset every 7 to 49 days through an auction process, thus limiting the Company’s exposure to interest rate risk. Interest and dividends are paid on these securities at the end of each reset period. At September 30, 2006, all of the auction rate securities were U.S. state and local municipal 86 securities due within one year. The Company’s auction rate securities are reported on the balance sheet at fair value. There were no unrealized gains or losses for 2006. The Company sold $91.6 million in auction rate securities during the year ended September 30, 2006 with no realized gains or losses. Interest and dividends related to these investments are included in interest and dividend income on the Company’s Consolidated Statements of Income. The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2006 and 2005. NOTE 9 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The table below presents changes in the components of accumulated other comprehensive income (loss). Balance at September 30, 2003 $39,851 $(72) $(6,111) $33,668 Unrealized Appreciation (Depreciation) on Securities Interest Rate Swap Minimum Pension Liability Total (in thousands) 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 2006 Change: Pre-income tax amount Income tax provision Realized gains in net income (net of $7,548 income tax) Balance at September 30, 2006 — — 72 72 — — — — — — — — $ — (1,951) 742 29,469 (11,198) — — (1,209) (7,320) (5,510) 2,094 (3,416) (10,736) 7,275 (2,765) 4,510 72 (15,759) 2,584 36,252 19,078 (7,249) (537) 11,292 47,544 55,515 (21,096) (12,318) 22,101 $(6,226) $69,645 31,420 (11,940) — (15,759) 3,721 43,572 24,588 (9,343) (537) 14,708 58,280 48,240 (18,331) (12,318) 17,591 $75,871 87 NOTE 10 EMPLOYEE BENEFIT PLANS The Company maintains a noncontributory defined pension plan for substantially all U.S. employees who meet certain age and service requirements. In July 2003, the Company revised the Helmerich & Payne, Inc. Employee Retirement Plan (‘‘Pension Plan’’) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were 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 (gain) loss Benefits paid Benefit obligation at end of year Change in plan assets: Years Ended September 30, Fair value of plan assets at beginning of year Actual gain on plan assets Employer contribution Benefits paid Fair value of plan assets at end of year Funded status of the plan Unrecognized net actuarial loss Unrecognized prior service cost Accumulated other comprehensive loss (before tax) Accrued benefit cost Weighted-average assumptions: Years Ended September 30, Discount rate Expected return on plan assets Rate of compensation increase 2006 2005 (in thousands) $90,217 $82,222 4,713 4,841 (5,903) (6,199) $87,669 3,480 4,617 3,408 (3,510) $90,217 2006 2005 (in thousands) $ 62,955 $ 56,650 5,575 4,421 (6,199) $ 66,752 $(20,917) 10,028 1 (10,042) $(20,930) 7,565 2,250 (3,510) $ 62,955 $(27,262) 17,445 1 (17,317) $(27,133) 2006 5.75% 8.00% 5.00% 2005 5.50% 8.00% 5.00% 2004 5.75% 8.00% 5.00% 88 The Company does not anticipate funding the Pension Plan in fiscal 2007 will be required. However, the Company can choose to make discretionary contributions to fund distributions in lieu of liquidating pension assets. During fiscal 2006, the Company elected to fund $4.4 million. The Company estimates contributing $3.0 million in fiscal 2007. Subsequent to year end, the Company has contributed $0.3 million to the Pension Plan. 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 Net pension expense 2006 $ 4,713 4,841 (4,936) (1) 876 $ 5,493 2005 (in thousands) $ 3,480 4,617 (4,378) — 987 $ 4,706 2004 $ 3,943 4,403 (4,232) 19 761 $ 4,894 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. 2007 2008 2009 2010 2011 Years Ended September 30, Total 2012-2016 $3,075 $3,328 $3,602 $3,769 $3,947 $24,010 $41,731 (in thousands) Included in the Pension Plan is an unfunded supplemental executive retirement plan. The accumulated benefit obligation for the defined Pension Plan was $87.7 million, $90.1 million and $75.7 million at September 30, 2006, 2005, and 2004, 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. 89 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. The target allocation for 2007 and the asset allocation for the domestic Pension Plan at the end of fiscal 2006 and 2005, 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, 2007 56% 14 25 5 100% 2006 60% 17 22 1 100% 2005 58% 16 24 2 100% The fair value of plan assets was $66.8 million and $63.0 million at September 30, 2006 and 2005, respectively, and the expected long-term rate of return on these plan assets was 8 percent in 2006 and 2005. 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 $8.4 million, $6.1 million, and $5.6 million in 2006, 2005, and 2004, respectively. FOREIGN PLAN The Company maintains an unfunded pension plan in one of the international subsidiaries. Pension expense was approximately $0.4 million, $0.3 million and $0.2 million in 2006, 2005 and 2004, respectively. The pension liability at September 30, 2006 and 2005 was $3.6 million and $3.4 million, respectively. NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in the Company’s reserve for bad debt for 2006, 2005 and 2004: September 30, Reserve for bad debt: Balance at October 1, Provision for bad debt Write-off of bad debt Balance at September 30, 2006 $1,791 250 (34) $2,007 2005 (in thousands) $1,265 530 (4) $1,791 2004 $1,319 15 (69) $1,265 90 Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following: September 30, Accounts receivable, net of reserve: 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 Accrued income taxes Workers’ compensation liabilities Payroll and employee benefits Accrued operating costs Other 2006 2005 (in thousands) $283,386 6,093 $289,479 $162,646 — $162,646 $ 2,597 $ 5,960 2,273 — 2,432 2,907 5,910 2,195 2,080 1,949 654 5,095 $ 16,119 $ 17,933 $ 21,316 $ 10,263 24,991 2,371 30,124 7,200 11,075 — 3,830 20,277 3,600 6,657 $ 97,077 $ 44,627 NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2006 Cash payments: Interest paid, net of amounts capitalized Income taxes paid $ 6,644 $109,857 2005 (in thousands) $12,707 $29,715 2004 $12,653 $ 7,010 Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2006, 2005 and 2004, does not include additions which have been incurred but not paid for as of the end of the 91 year. The following table reconciles total capital expenditures incurred to total capital expenditures in the Consolidated Statements of Cash Flows: September 30, Capital expenditures incurred Additions incurred prior year but paid for in current year Additions incurred but not paid for as of the end of the year Capital expenditures per Consolidated Statements of 2006 $614,274 10,351 (95,720) 2005 (in thousands) $95,007 2,149 (10,351) 2004 $88,972 3,389 (2,149) Cash Flows $528,905 $86,805 $90,212 NOTE 13 RISK FACTORS CONCENTRATION OF CREDIT Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments, short-term 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, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of the Company’s international sales, however, are to large international or national companies. The Company performs ongoing credit evaluations of customers and does not typically require collateral in support for trade receivables. 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 in recent history. 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 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. In 2005 the Company formed a wholly-owned captive insurance company, White Eagle Assurance Company (White Eagle), to provide a portion of the Company’s property damage insurance for company-owned drilling rigs. The Company obtained 85 percent of rig property insurance from a third party insurance provider in 2006 that carried a $1.0 million deductible. The Company is self insured through White Eagle for the remaining 15 percent of rig property coverage and the $1.0 million deductible on all rig property. Additionally, the Company utilizes White Eagle to finance self insured losses within the $1.0 million per occurrence 92 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 a significant contributor to the Company’s revenues and net operating income. There can be no assurance that the Company will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on the Company’s financial position, results of operations, and cash flows. Also, the success of the Company’s international operations will be subject to numerous contingencies, some of which are beyond management’s control. These contingencies include general and regional economic conditions, fluctuations in currency exchange rates, changes in international regulatory requirements and international employment issues, and the burden of complying with foreign laws. The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, approximately 60 percent of the Company’s billings to the Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar. 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. On October 1, 2003, in compliance with applicable regulations, the Company 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 was the first dividend remitted under the new regulation. On January 16, 2006, a dividend of $6.5 million was paid to the U.S. based parent. These dividends reduced the Company’s exposure to currency devaluation in Venezuela. On August 18, 2006, 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. The Company anticipates the dividend to be approximately $9.3 million. 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 at September 30, 2006 and 2005, respectively, and 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. Even though Venezuela continues to operate under the exchange controls in place and the Venezuelan bolivar exchange rate has remained fixed at 2150 bolivares to one U.S. dollar since the devaluation in March, 2005, the exact amount and timing of devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2007 activity levels are similar to fiscal 2006 and if a 10 percent to 20 percent devaluation would 93 occur, the Company could experience potential currency devaluation losses ranging from approximately $1.5 million to $2.8 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 to receiving these payments in bolivares and thus increase bolivar cash balances and exposure to devaluation. Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in labor and/or material and supplies necessary to operate some or all of its Venezuelan drilling rigs, thereby causing an adverse effect on the Company. The Company derives its revenue in Venezuela from Petr´oleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company. At September 30, 2006, the Company had a net receivable from PDVSA of $45.4 million of which $16.2 million was 90 days old or older. At December 1, 2006, such receivable balance had increased to approximately $66 million, of which $40 million was 90 days old or older. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than that of other customers in international countries in which the Company has drilling operations. In order to establish a source of local currency to meet current obligations in Venezuela bolivares, the Company is borrowing in the form of short-term notes from two local banks in Venezuela at the market interest rates designated by the banks. NOTE 14 COMMITMENTS AND CONTINGENCIES COMMITMENTS During fiscal years 2006 and 2005, the Company entered into separate drilling contracts with 16 exploration and production customers to build and operate a total of 66 new FlexRigs. Subsequent to September 30, 2006, the Company announced that agreements had been reached with three exploration and production companies to operate an additional seven new FlexRigs bringing the total of the new rigs to 73. The construction of the 73 rigs is estimated to cost $1.1 billion. Approximately $400 million was incurred in fiscal 2006 and approximately $600 million is expected to be incurred in fiscal 2007. The construction began in the third quarter of fiscal 2005 and is estimated to continue through the first quarter of fiscal 2008. 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, 2006, the Company had commitments outstanding of approximately $313.2 million for the purchase of drilling equipment. 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 94 also conducts certain operations in leased premises and leases telecommunication equipment. Future minimum lease payments required under noncancelable operating leases as of September 30, 2006 are as follows (in thousands): Fiscal Year 2007 2008 2009 2010 Thereafter Total Amount $ 3,694 2,726 1,715 502 — $ 8,637 Total rent expense was $3.1 million, $2.3 million and $2.0 million for 2006, 2005 and 2004, respectively. CONTINGENCIES In August 2006, the Company signed an option agreement to sell two U.S. offshore rigs. The net book value of the two rigs at September 30, 2006 was approximately $4.2 million and has been classified as ‘‘Assets held for sale’’ in the Company’s September 30, 2006 Consolidated Balance Sheet. In September 2006, the Company received $2.0 million from the optionee for exclusive rights to purchase the rigs. The $2.0 million is classified in current liabilities in the Consolidated Balance Sheet at September 30, 2006. An additional $6.0 million was received in October 2006 to exercise the extended option term. If the purchase option is exercised, the transaction will close in the second quarter of fiscal 2007. 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 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. Capital costs incurred in conjunction with rebuilding the rig are capitalized and depreciated as described in Note 1 Summary of Significant Accounting Policies. Insurance proceeds of approximately $3.0 million were received in fiscal 2006. Such proceeds approximate the net book value of equipment lost in the hurricane and therefore, no gain was recognized in fiscal 2006. The proceeds are in the Consolidated Statements of Cash Flows under investing activities. Subsequent to September 30, 2006, additional insurance proceeds of $0.3 million have been received and additional claims have been submitted. Because the rig is still under repair, the Company is unable to estimate the amount or timing of the gain. NOTE 15 SEGMENT INFORMATION The Company operates principally in the contract drilling industry. The Company’s contract drilling business includes the following reportable operating segments: U.S. Land, U.S. Offshore, 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, 95 Colombia, Ecuador, other South American countries and Africa. The International operations have similar services, have similar types of customers, operate in a consistent manner and have similar economic and regulatory characteristics. Therefore, the Company has aggregated its International operations into one reportable segment. The Company also has a Real Estate segment whose operations are conducted exclusively in the metropolitan area of Tulsa, Oklahoma. The key areas of operation include 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. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. The Company evaluates segment performance based on income or loss from operations (segment operating income) before income taxes which includes: revenues from external and internal customers (cid:127) (cid:127) direct operating costs (cid:127) depreciation and (cid:127) allocated general and administrative costs but excludes corporate costs for other depreciation, income from asset sales and other corporate 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. Segment operating income for all segments is a non-GAAP financial measure of the Company’s performance, as it excludes general and administrative expenses, corporate depreciation, income from asset sales and other corporate income and expense. The Company considers segment operating income to be an important supplemental measure of operating performance for presenting trends in the Company’s core businesses. This measure is used by the Company to facilitate period-to-period comparisons in operating performance of the Company’s reportable segments in the aggregate by eliminating items that affect comparability between periods. The Company believes that segment operating income is useful to investors because it provides a means to evaluate the operating performance of the segments and the Company on an ongoing basis using criteria that are used by our internal decision makers. Additionally, it highlights operating trends and aids analytical comparisons. However, segment operating income has limitations and should not be used as an alternative to operating income or loss, a performance measure determined in accordance with GAAP, as it excludes certain costs that may affect the Company’s operating performance in future periods. 96 Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2006, 2005, and 2004 is shown in the following table: External Sales Inter- Segment Total Sales Segment Operating Income (Loss) Depreciation Total Assets Additions to Long-Lived Assets (in thousands) 2006 Contract Drilling U.S. Land $ 829,062 $ — $ 829,062 $351,255 $ 66,127 $1,356,817 $560,664 U.S. Offshore International Real Estate Other Eliminations 132,580 252,792 1,214,434 10,379 1,224,813 — — — — 783 783 — — (783) 132,580 252,792 27,007 57,176 1,214,434 435,438 11,162 4,411 11,360 19,512 96,999 2,444 110,192 311,605 18,553 31,448 1,778,614 610,665 30,626 1,275 1,225,596 439,849 99,443 1,809,240 611,940 — (783) — — 2,140 — 325,472 — 2,334 — Total $1,224,813 $ — $1,224,813 $439,849 $101,583 $2,134,712 614,274 2005 Contract Drilling U.S. Land $ 527,637 $ — $ 527,637 $164,657 $ 60,222 $ 809,403 $ 78,499 U.S. Offshore International Real Estate Other Eliminations 84,921 177,480 790,038 10,688 800,726 — — — — 761 761 — — (761) 84,921 177,480 790,038 11,449 17,708 18,973 201,338 4,714 10,602 20,107 90,931 2,352 95,108 239,087 1,143,598 32,203 801,487 206,052 93,283 1,175,801 — (761) — — 2,991 487,549 — — 1,058 12,438 91,995 1,517 93,512 1,495 — Total $ 800,726 $ — $ 800,726 $206,052 $ 96,274 $1,663,350 95,007 2004: Contract Drilling U.S. Land $ 346,015 $ — $ 346,015 $ 35,545 $ 56,528 $ 742,642 $ 68,680 U.S. Offshore International Real Estate Other Eliminations 84,238 148,788 579,041 10,015 589,056 — — — — 897 897 — — (897) 84,238 148,788 579,041 10,912 589,953 — (897) (35,628) 12,126 12,043 3,198 15,241 — — 12,107 20,530 89,165 2,253 102,557 261,893 1,107,092 33,044 91,418 1,140,136 3,007 — 266,708 — 1,512 9,513 79,705 3,538 83,243 5,729 — Total $ 589,056 $ — $ 589,056 $ 15,241 $ 94,425 $1,406,844 $ 88,972 97 The following table reconciles segment operating income to income before taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, Segment operating income Income from asset sales Corporate general and administrative costs and corporate depreciation Operating income (loss) Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Total unallocated amounts 2006 $439,849 7,492 (30,055) 417,286 9,834 (6,644) 19,866 639 23,695 2005 $206,052 13,550 (26,846) 192,756 5,809 (12,642) 26,969 (235) 19,901 2004 $ 15,241 5,377 (27,503) (6,885) 1,965 (12,695) 25,418 197 14,885 Income before income taxes and equity in income of affiliate $440,981 $212,657 $ 8,000 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, 2006 2005 2004 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $ 972,021 $623,246 $440,268 84,594 88,709 17,748 61,741 66,824 60,946 12,792 36,918 56,297 43,363 3,698 45,430 $1,224,813 $800,726 $589,056 $1,284,235 $810,489 $799,207 83,160 42,859 9,793 63,087 84,461 44,250 9,213 33,552 85,336 46,809 9,336 57,986 $1,483,134 $981,965 $998,674 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 11.2 percent, 11.1 percent, and 11.4 percent of the total operating revenues during the years ended September 30, 2006, 2005, and 2004, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 7.1 percent, 8.7 percent, and 11.3 percent of total operating revenues in the years ended September 30, 2006, 2005, and 2004, respectively. Collectively, the 98 receivables from these customers were approximately $45.3 million and $29.2 million at September 30, 2006 and 2005, respectively. NOTE 16 SUBSEQUENT EVENTS On November 16, 2006, the Company announced three-year term contracts had been reached with three exploration and production companies to operate seven new FlexRigs. With these contracts, the Company has now committed to build 73 new FlexRigs, of which 24 had been completed as of September 30, 2006. Subsequent to September 30, 2006, the Company sold 500,000 shares of an available-for-sale security resulting in a gain of approximately $26.2 million, $16.0 million after-tax. Proceeds from the sales were $30.2 million. Subsequent to September 30, 2006, the Company repurchased 681,900 shares of Company common stock at an aggregate price of $15.9 million, or an average share price of $23.26 per common share. On December 5, 2006, a cash dividend of $.045 per share was declared for shareholders of record on February 15, 2007, payable March 1, 2007. On December 5, 2006, the Board of Directors granted 728,525 nonqualified and incentive stock options and 27,000 restricted stock awards to employees and non-employee Directors under the 2005 Long-Term Incentive Plan. NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2006 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (in thousands, except per share amounts) Operating revenues Operating income Net income Basic net income per common share Diluted net income per common share $255,388 $290,830 $319,796 $358,799 80,904 50,814 .49 .48 100,251 64,573 .62 .61 114,137 79,975 .76 .75 121,994 98,496 .94 .93 2005 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues Operating income Net income Basic net income per common share Diluted net income per common share $174,679 $185,450 $207,387 $233,210 38,557 22,350 .22 .22 51,421 29,825 .29 .28 61,043 36,121 .35 .34 41,735 39,310 .39 .38 99 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. The fourth quarter of fiscal 2006 includes adjustments to deferred tax accounts in certain international locations resulting in an increase of $0.12 per share, on a diluted basis. In the first quarter of fiscal 2006, net income includes an after-tax gain on sale of available-for-sale securities of $1.7 million, $0.02 per share on a diluted basis. In the third quarter of fiscal 2006, net income includes an after-tax gain on sale of available-for-sale securities of $5.8 million, $0.05 per share on a diluted basis. In the fourth quarter of fiscal 2006, net income includes an after-tax gain on sale of available-for-sale securities of $4.8 million, $0.05 per share on a diluted basis. In the first quarter of fiscal 2005, net income includes an after-tax gain on sale of available-for-sale securities of $16.0 million, $0.15 per share, on a diluted basis. 100 Directors Officers W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer Douglas E. Fears Vice President and Chief Financial Officer Steven R. Mackey Vice President, Secretary, and General Counsel John W. Lindsay Executive Vice President, Helmerich & Payne International Drilling Co. M. Alan Orr Executive Vice President, Helmerich & Payne International Drilling Co. W. H. Helmerich, III Chairman of the Board Tulsa, Oklahoma Hans Helmerich President and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong**(***) President Colorado Christian University Lakewood, Colorado Glenn A. Cox*(***) President and Chief Operating Officer, Retired Phillips Petroleum Company Bartlesville, Oklahoma George S. Dotson Vice President, Retired President of Helmerich & Payne International Drilling Co., Retired, Tulsa, Oklahoma Paula Marshall**(***) 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 101 Stockholders’ Meeting The annual meeting of stockholders will be held on March 7, 2007. 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, 2007. 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, 2006, there were 758 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 effi- ciently answered by corresponding directly with The Trans- fer 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 website. Also located on the investor relations section of the Company’s website are certain corporate governance documents, including the following: the charters of the committees of the Board of Directors; the Company’s Corporate Governance Guide- lines and Code of Business Conduct and Ethics; the Code of Ethics for Principal Executive Officer and Senior Finan- cial 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 communi- cation of such concerns confidentially and anonymously via the Company’s ethics hotline at 1-800-205-4913. Quar- terly 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 Sec- tion 303A.12(a) of the New York Stock Exchange Listed Company Manual was provided to the New York Stock Exchange on or about March 23, 2006. 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 13DEC200618215634 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 ANNUAL REPORT FOR 2006