Helmerich & Payne
Annual Report 2007

Plain-text annual report

HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2007 5DEC200714412927 Helmerich & Payne, Inc. is the holding Company for H e l m e r i c h & Pa y n e , I n 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 securities valued at approximately $458 million as of September 30, 2007. F I N A N C I A L H I G H L I G H T S 5DEC200714525485 Years Ended September 30, 2007 2006 2005 Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets (in thousands, except per share amounts) $1,629,658 449,261 4.27 .1800 894,214 2,885,369 $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 To the Co-owners of Helmerich & Payne, Inc.: We are pleased to report the Company’s third consecutive year of record setting results, particularly when this accomplishment comes a year after the cycle peaked out in terms of drilling rig market pricing in the U.S. Our strategy has never been based on cyclical highs and rig scarcity, where demand has to outstrip the available supply of drilling rigs and where customers pay more for any available rig. We have long believed that a more enduring approach is to enable the customer to achieve a lower total well cost by delivering superior service using the safest, newest, and most innovative rigs in the industry. Throughout this past year, we achieved an unprecedented pace of adding four rigs per month to our fleet. Perhaps 2007’s most significant accomplishment is found less in the financials and more in the on-time, on-cost execution of that aggressive program. It’s a credit to our people to daily deliver on the entire value chain involved: design, manufacturing, commissioning, training, and field performance. While it is fitting in these pages to recognize their dedication and contribution to the Company’s accomplishment, it is a customer’s endorsement of the FlexRig that, in the end, signals a buy-in to the people who stand behind the outstanding performance. In the coming year, we will be managing to the same challenges and opportunities we have talked about for a long time: (cid:127) Deliver growth to shareholders by securing and executing on an aggressive order book. (cid:127) Win the customer’s trust by consistently and safely providing differentiated field results. (cid:127) Take advantage of an ongoing retooling effort in an increasingly segmented industry still top-heavy with old, less capable rigs. (cid:127) Expand into additional drilling markets, with more focus on expanding our international effort. While this is not an exhaustive list, it should be familiar to our regular readers. Perhaps most notable is what the list excludes. Namely, that we are not managing the dilemma of carrying a large percentage of old, less capable rigs, while the customer increasingly votes in favor of high efficiency rig offerings. Too many old legacy assets, often no longer suitable for reinvestment, force our peers into a tradeoff between market share and price discipline. That sounds like the classic prisoner’s dilemma with the logical best choice being price discipline. Since, after all, the market drives demand, contractors have to fight against being reduced in a soft environment and engaging in the downward spiral of rig-on-rig price destruction. This is happening now in the U.S. land drilling market. Some industry observers have asked why drilling contractors are not exerting more pricing discipline in a market with historically high rig counts. One reason is that truly differentiated performance has driven a segmented marketplace. What we see from our end is existing FlexRigs that were working on the spot market in the last quarter of 2007 still commanding over $25,000 in rig revenue per day on average at 100 percent utilization, while competing rigs were aggressively cutting prices and in the end were still pushed to the sidelines. Take a look at this last year in terms of margins and activity by comparing the fourth quarter of fiscal 2007 to that of fiscal 2006: (cid:127) Our average rig margin per day in the U.S. land market has only declined by eight percent to $12,221. This daily margin is now 40 percent greater than that of our four largest peers. (cid:127) Moreover, our quarterly average number of active rigs increased by 38 percent year-over-year, while that of our four largest peers combined experienced a net reduction of 14 percent. We have passed the point where competitors can credibly position idle, old equipment as future operating leverage. Back to the prisoner’s dilemma, the next logical exercise in discipline is to permanently remove from the market old industry rigs that are increasingly obsolete, ill-suited, and potentially unsafe in a drilling environment that is becoming more technically demanding. All of this reinforces our confidence in a retooling theme that continues to provide us attractive opportunities going forward. The new order for six FlexRigs that we announced this month provides further confirmation that even in a softer market, the customer is supporting the Company’s value proposition. Sincerely, Hans Helmerich President 11DEC200619131880 November 28, 2007 Financial & Operating Review Years Ended September 30, 2007 2006 2005 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 Offshore Platform International Land Total Rig Fleet Rig Utilization Percentage – U. S. Land – FlexRigs U. S. Land – Highly Mobile U. S. Land – Conventional U. S. Land – All Rigs Offshore Platform International Land $1,629,658 862,254 146,042 47,401 632,319 4,234 65,458 10,126 449,261 449,261 $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 4.27 4.27 2.77 2.77 1.23 1.23 $ 89,215 272,352 223,360 2,152,616 2,885,369 445,000 1,815,516 894,214 $ 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 86,805 118 12 27 9 27 193 100 93 87 97 65 90 73 12 28 9 27 149 100 100 95 99 69 90 50 12 29 11 26 128 100 99 82 94 53 77 2004 2003 2002 2001 2000 1999 1998 1997 $ 589,056 417,716 145,941 37,661 (6,885) 1,965 25,418 12,695 4,359 4,359 $ 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 .04 .04 .18 .18 .53 .63 .79 1.42 .36 .82 .32 .43 .80 1.00 .48 .83 $ 65,296 185,427 161,532 998,674 1,406,844 200,000 914,110 90,212 $ 38,189 110,848 158,770 1,058,205 1,417,770 200,000 917,251 242,912 $ 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 48 11 28 11 32 130 99 91 67 87 48 54 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 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 0 7 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (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, 2007 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:1) 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, 2007 the aggregate market value of the voting stock held by non-affiliates was $3,025,489,023 Number of shares of common stock outstanding at November 21, 2007: 103,502,581 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, 2007 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 5, 2008 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 7, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 34 THROUGH 67 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, 2007 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 Management’s 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, Executive Officers and Corporate Governance 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, and Director Independence Item 14. Principal Accountant Fees and Services Item 15. Exhibits and Financial Statement Schedules SIGNATURES PART IV Page 1 7 13 13 18 18 18 19 20 20 20 21 21 21 24 25 25 25 25 25 25 30 ii (This page intentionally left blank.) 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, 2007 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, offshore platform drilling and international land drilling. The Company’s U.S. land drilling is conducted primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Alabama, Arkansas, New Mexico, and North Dakota, and offshore from platforms in the Gulf of Mexico, California, Trinidad and Equatorial Guinea. The Company’s international land segment operated in seven international locations during fiscal 2007: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Tunisia, and Chile. The Company’s real estate investments are located in Tulsa, Oklahoma, where the Company maintains its executive offices. CONTRACT DRILLING General 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 2007, the Company received approximately 55 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers. BP plc, Petroleos de Venezuela S.A. and Marathon Oil Company (respectively, ‘‘BP’’, ‘‘PDVSA’’ and ‘‘Marathon’’), including their affiliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for BP on a world-wide basis, PDVSA in Venezuela and Marathon in the U.S. land operations. Revenues from drilling services performed for BP, PDVSA and Marathon in fiscal 2007 accounted for approximately 11 percent, 8 percent and 6 percent, respectively, of the Company’s consolidated operating revenues for the same period. Rigs, Equipment and Facilities 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 rigs’’, 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. Since fiscal 2005, the Company has entered into separate drilling contracts with 19 exploration and production companies to build and operate a total of 83 new FlexRigs. Of the 83 FlexRigs, 27 are FlexRig3s and 56 are FlexRig4s (described below). Each of the drilling contracts provides for a minimum fixed contract term of at least three years, with drilling services to be performed on a daywork contract basis. All 83 FlexRigs are expected to be completed by the end of the third quarter of fiscal 2008. The total construction cost for the 83-rig project is expected to approximate $1.3 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 results in reduced environmental impact. The effective use of technology is important to the maintenance of the Company’s competitive position within the drilling industry. As a result of the importance of technology to the Company’s business, we expect to continue to develop technology internally. During fiscal 2005 and 2006, the Company experienced labor cost increases and labor shortages in both fabrication and rig-up services primarily as a result of Hurricanes Katrina and Rita. The hurricane-related damage significantly affected the Company’s principal fabricator of rig components and caused FlexRig production delays and increased rig costs. Delivery schedules of the new FlexRigs were pushed back to such a degree that late-delivery contractual liquidated damage payments were incurred during fiscal 2005, 2006 and 2007. However, the incurred liquidated damage payments have had, and are expected to have, an immaterial impact on revenues and margins. Absent the occurrence of any of the risks described in “Risk Factors” beginning on page 7, no liquidated damage payments are expected to be incurred after October 16, 2007. The Company assembles new FlexRigs in its gulf coast facility near Houston, Texas. During fiscal 2007, the Company purchased a 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma. This facility will expand the Company’s existing capacity for the fabrication and assembly of rig components. Drilling Contracts The Company’s drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and often cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract. During fiscal 2007, all drilling services were performed on a ‘‘daywork’’ 2 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 has not accepted any ‘‘footage’’ or ‘‘turnkey’’ contracts for at least the last ten years. 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 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 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 83 FlexRig new-build projects, the Company had 22 rigs under fixed term contracts as of the end of September 2007. While the original 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. Backlog The Company’s contract drilling backlog, consisting of executed contracts with original terms in excess of one year, as of October 31, 2007 and 2006 was $1.969 billion and $2.116 billion, respectively. Approximately 59.1 percent of the total October, 2007 backlog is not reasonably expected to be filled in fiscal 2008. Term 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 delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. In addition, a portion of the backlog represents term contracts for new rigs that will be constructed in the future. The Company obtains certain key rig components from a single or limited number of vendors or fabricators. Certain of these vendors or fabricators are thinly capitalized independent companies located on the Texas gulf coast. Therefore, disruptions in rig component deliveries may occur. Accordingly, the actual amount of revenue earned may vary from the backlog reported. See ‘‘Fixed Term Contract Risk’’, ‘‘Limited Number of Vendors’’, ‘‘Thinly Capitalized Vendors’’ and ‘‘Operating and Weather Risks’’ under Item ‘‘1A. Risk Factors.’’ 3 The following table sets forth the total backlog by reportable segment as of October 31, 2007 and 2006, and the percentage of the October 31, 2007 backlog not reasonably expected to be filled in fiscal 2008: Reportable Segment U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Total Backlog 10/31/2007 10/31/2006 (in billions) $1.696 .234 .039 $1.969 $1.949 .078 .089 $2.116 Percentage Not Reasonably Expected to be Filled in Fiscal 2008 57.2% 82.5% 0.0% U.S. LAND DRILLING At the end of September, 2007, 2006 and 2005, the Company had 156, 110 and 91 respectively, of its land rigs available for work in the United States. The total number of rigs owned at the end of fiscal 2007 increased by a net of 46 rigs from the end of fiscal 2006. The change from fiscal 2006 to fiscal 2007 resulted from 48 new FlexRigs placed into service, the sale of one conventional rig in June 2007, and the loss of one FlexRig2 in a well blowout fire in August 2007. One additional FlexRig was completed as of September 30, 2007, and was ready for delivery. The Company’s U.S. land operations contributed approximately 72 percent of the Company’s consolidated operating revenues during fiscal 2007, compared with approximately 68 percent of consolidated operating revenues during fiscal 2006 and approximately 66 percent of consolidated operating revenues during fiscal 2005. Rig utilization in fiscal 2007 was approximately 97 percent, down from approximately 99 percent in fiscal 2006. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 99 percent during fiscal 2007 while the Company’s conventional rigs had an average utilization rate of approximately 87 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 2007, 147 land rigs were working out of 156 available rigs. OFFSHORE PLATFORM DRILLING The Company’s offshore platform operations contributed approximately 8 percent of the Company’s consolidated operating revenues during fiscal 2007, compared to approximately 13 percent of the Company’s consolidated operating revenues during both fiscal 2006 and 2005. Rig utilization in fiscal 2007 was approximately 65 percent, down from approximately 69 percent in fiscal 2006. At the end of fiscal 2007, the Company had seven of its nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. The management contract for one rig located offshore Equatorial Guinea is expected to terminate in December 2007. Revenues from drilling services performed for the Company’s largest offshore platform drilling customer totaled approximately 45 percent of offshore platform revenues during fiscal 2007. During fiscal 2007, the Company sold two offshore rigs. An option agreement for the sale was in place at the end of 2006 and the assets were classified as held for sale in the Company’s Consolidated Financial Statements. The rigs were 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. Insurance proceeds that approximated replacement cost were used to rebuild the rig. The rig returned to service during the fourth quarter of fiscal 2007. INTERNATIONAL LAND DRILLING General The Company’s international land operations contributed approximately 20 percent of the Company’s consolidated operating revenues during fiscal 2007, compared with approximately 19 percent of consolidated operating revenues during fiscal 2006 and 2005. Rig utilization in fiscal 2007 and 2006 was 90 percent. 4 Venezuela Venezuelan operations continue to be a significant part of the Company’s operations. The Company worked exclusively for the Venezuelan state petroleum company, PDVSA, during fiscal 2007 and revenues from this work accounted for approximately 40 percent of international operating revenues. Revenues generated from Venezuelan drilling operations contributed approximately 8 percent ($127.3 million) of the Company’s consolidated operating revenues during 2007, compared with approximately 7 percent ($84.6 million) of consolidated operating revenues during fiscal 2006 and 8 percent ($66.8 million) of consolidated operating revenues during 2005. The Company had ten rigs working in Venezuela at the end of fiscal 2007. The Company’s rig utilization rate in Venezuela increased from approximately 83 percent during fiscal 2006 to approximately 92 percent in fiscal 2007. The Company expects to return one idle rig back to work during the first quarter of fiscal 2008. Ecuador At the end of fiscal 2007, the Company owned eight rigs in Ecuador. The Company’s utilization rate was 89 percent during fiscal 2007, down from 100 percent in fiscal 2006. Revenues generated by Ecuadorian drilling operations contributed approximately 6 percent ($93.9 million) of the Company’s consolidated operating revenues during fiscal 2007, as compared with approximately 7 percent ($88.7 million) of consolidated operating revenues during fiscal 2006 and approximately 8 percent ($60.9 million) of consolidated operating revenues during fiscal 2005. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 2 percent of consolidated operating revenues and approximately 11 percent of international operating revenues during fiscal 2007. The Ecuadorian drilling contracts are primarily with large international oil companies. The Ecuadorian government continues to negotiate with the Company’s customers to resolve contract disputes created by a recent government decree. The decree modified the original contracts for splitting profits on oil production. If this continues without resolution, the Company anticipates that up to seven rigs could be idle in Ecuador in the second quarter of fiscal 2008. Should this situation occur, the Company, at this time, is unable to predict the length of time that the rigs would remain idle. Other Locations In addition to its operations in Venezuela and Ecuador, at the end of fiscal 2007, the Company owned three rigs in Argentina, two rigs in Colombia and one rig in each of Bolivia, Chile, and Tunisia. At the end of November 2007, all rigs in Argentina, Colombia and Tunisia were fully employed. The rig in Bolivia was being mobilized to Argentina at the end of November 2007, and is expected to begin operations there during the second quarter of fiscal 2008. The rig in Chile was being demobilized at the end of November 2007. REAL ESTATE OPERATIONS The Company’s real estate operations contributed less than one percent of the Company’s consolidated operating revenues during fiscal 2007 and fiscal 2006 compared with approximately one percent of the Company’s consolidated operating revenues during fiscal 2005. The 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 440,995 leasable square feet, composed of retail space of 377,619 leasable square feet, office space of 39,400 leasable square feet, storage space of 6,794 leasable square feet and common area space of 17,182 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 approximately 92 percent in fiscal 2006 to approximately 94 percent in fiscal 2007. At the end of the 2007 fiscal year, the Company owned 8 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. Five of the Company’s units are currently leased. 5 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 unchanged from fiscal 2006. 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 2007, the Company owned approximately 218 acres in Southpark consisting of approximately 205 acres of undeveloped real estate and approximately 13 acres of multi-tenant warehouse area. The warehouse area is known as Space Center East and consists of two warehouses, one containing approximately 90,000 square feet and the other containing approximately 112,500 square feet. Occupancy increased to approximately 91 percent in 2007 from approximately 76 percent in fiscal 2006 due to the addition of three new tenants. The Company believes that a high quality office park, with peripheral commercial, office/warehouse, and hotel sites, is the best development use for the remaining land. A professional engineering and planning firm has prepared a topographic survey and preliminary site engineering plan to aid in the possible future development of Southpark. The Company and the City of Tulsa are currently in the process of reviewing such plans, including hydrology studies and utility plans. The Company owns a five-building complex called Tandem Business Park. The property is located adjacent to and east of the Space Center East facility and contains approximately six acres, with approximately 88,084 square feet of office/warehouse space. Occupancy has increased from approximately 72 percent in 2006 to approximately 80 percent during fiscal 2007 due to the addition of two tenants. The Company also owns a 12-building complex, consisting of approximately 204,600 square feet of office/ warehouse space, called Tulsa Business Park. The property is located south and east of the Space Center facility, separated by a city street, and contains approximately 12 acres. During fiscal 2007, occupancy increased from approximately 74 percent to approximately 86 percent due to the addition of three new tenants. 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 2007, occupancy decreased to approximately 46 percent from approximately 61 percent due to the loss of one large tenant. The second, called Maxim Place, consists of one office/warehouse building containing approximately 33,750 square feet and is located on approximately 2.25 acres. During fiscal 2007, occupancy has 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 by reportable operating segments may be found on, and is incorporated by reference to, pages 100 through 103 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). EMPLOYEES The Company had 4,985 employees within the United States (12 of which were part-time employees) and 1,471 employees in international operations as of September 30, 2007. 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 106 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). 6 Item 1A. RISK FACTORS In addition to the risk factors discussed elsewhere in this Report, the Company cautions that the following ‘‘Risk Factors’’ could have a material adverse effect on the Company’s business, financial condition and results of operations. 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 and type 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, 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’s and have more contemporary facilities. 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 returned to normal drilling operations in 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 7 rig, bankruptcy, sustained unacceptable performance by the Company, or 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 Insurance coverage for ‘‘named storms’’ in the Gulf of Mexico has been limited for the past two years. The Company purchased an aggregate limit of $75 million of wind storm coverage and self-insures 20 percent of that limit as well as a $2.5 million deductible. Additionally, the Company obtained rig property insurance for 80 percent of the aggregate estimated replacement cost of its rigs in excess of a $1 million per occurrence deductible. The Company self insures the remaining 20 percent of such rig value as well as the deductible. 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 has insurance coverage for comprehensive general liability, automobile liability, worker’s compensation, and employer’s liability. Generally, casualty 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 deductibles as high as $5 million. Insurance is purchased over deductibles to reduce the Company’s exposure to catastrophic events. The Company retains a significant portion of its expected losses under its worker’s compensation, general liability, and automobile liability programs. The Company records estimates for incurred outstanding liabilities for unresolved worker’s compensation, general liability, 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. 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, 8 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 adverse effect on the Company’s business, financial condition or results of operations. 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. 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, which could have a material adverse effect on the Company’s business, financial condition or results of operations. 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 2007, approximately 20 percent of the Company’s consolidated operating revenues were generated from the international contract drilling business. Approximately 95 percent of the international operating revenues were from operations in South America and approximately 73 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 immaterial 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 an insignificant level 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 exchange rate between the U.S. dollar and the Argentine peso has stayed within a narrow range for the past four years and in fiscal 2007 the Company experienced an immaterial currency loss. 9 Venezuela The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, approximately 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 paid in bolivares. However, this arrangement is effective only in the absence of exchange controls. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the Central Bank. As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivares into U.S. dollars. In compliance with such regulations, the Company, in October of 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which would convert 14 billion bolivares into U.S. dollars. In January 2004, the Venezuelan government approved the Company’s request to convert bolivar cash balances to U.S. dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S. based parent. 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. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by these amounts. On June 7, 2007, the Company began the process to make 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 $8.3 million as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation. While the Company has been successful in obtaining government approval for conversion of bolivares to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then bolivar cash balances would increase and expose the Company to increased risk of 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. At September 30, 2007, the Company had a $25.6 million cash balance denominated in bolivares exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2008 activity levels are similar to fiscal 2007, and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $3.5 million to $6.4 million. 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 2007, the Company had a net receivable from PDVSA of approximately $49.7 million, of which approximately $12.0 million was 90 days old or older. At November 1, 2007, such receivable balance had increased to approximately $50.3 million, of which approximately $14.4 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, 10 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 business, financial condition and results of operations. 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 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 At September 30, 2007, the Company had outstanding, $175 million intermediate-term unsecured debt with staged maturities from August 2009 to August 2014, with varying fixed interest rates for each maturity series. The average interest rate during the next four years on this debt is 6.5 percent, after which it increases to 6.6 percent. The fair value of this debt at September 30, 2007 was approximately $182 million. In December 2006, the Company entered into an agreement for a five-year $400 million senior unsecured credit facility. The Company had $270 million borrowed and two letters of credit totaling $20.9 million outstanding against the facility at September 30, 2007. The interest rate on the borrowings is based on a spread over LIBOR and the Company pays a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of the Company’s total debt to total capitalization. The Company also has the option to borrow at the prime rate for maturities of less than 30 days. Also in December 2006, the Company entered into an agreement with a single bank to amend and restate the previous unsecured line of credit from $50 million to $5 million. The interest rate on borrowings is equal to the prime rate minus 1.75%. At September 30, 2007, the Company had no outstanding borrowings against the credit line. 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, 2007, the Company had a portfolio of securities with a total market value of $457.5 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 2007, the Company received approximately 55 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 11 larger customers would have a material adverse effect on the Company’s business, financial condition or 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 business, financial condition or 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. 12 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 2007 fiscal year and that remain unresolved. Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning the Company’s U.S. drilling rigs as of September 30, 2007: Location FLEXRIGS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS WYOMING WYOMING OKLAHOMA TEXAS TEXAS LOUISIANA TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS NEW MEXICO COLORADO TEXAS OKLAHOMA TEXAS TEXAS TEXAS LOUISIANA TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS Rig Optimum Depth Rig Type Drawworks: Horsepower 164 165 166 167 168 169 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 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 13 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) 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 Location TEXAS CALIFORNIA TEXAS TEXAS COLORADO CALIFORNIA WYOMING TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA TEXAS COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO NEW MEXICO NEW MEXICO NEW MEXICO WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS COLORADO COLORADO COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS WYOMING TEXAS TEXAS Rig 235 236 237 238 239 240 241 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 292 293 294 295 296 297 298 299 300 Optimum Depth Rig Type Drawworks: Horsepower AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (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) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) 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 14,000 14,000 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 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14 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 1,150 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location TEXAS TEXAS TEXAS TEXAS TEXAS NEW MEXICO WYOMING WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS TEXAS WYOMING COLORADO COLORADO COLORADO COLORADO COLORADO TEXAS HIGHLY MOBILE RIGS ARKANSAS OKLAHOMA TEXAS WYOMING OKLAHOMA TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS WYOMING CONVENTIONAL RIGS OKLAHOMA OKLAHOMA TEXAS OKLAHOMA TEXAS TEXAS WYOMING LOUISIANA OKLAHOMA LOUISIANA TEXAS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS TEXAS Rig 301 302 303 304 305 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 140 158 156 159 141 142 143 145 155 146 147 154 110 96 118 119 120 171 172 122 162 79 80 89 92 94 98 97 99 137 Optimum Depth Rig Type Drawworks: Horsepower 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 SCR SCR SCR SCR SCR 8,000 8,000 8,000 8,000 8,000 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 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 20,000 20,000 26,000 26,000 26,000 15 1,150 1,150 1,150 1,150 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 900 900 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,500 700 1,000 1,200 1,200 1,200 1,000 1,000 1,700 1,500 2,000 1,500 1,500 1,500 1,500 1,500 2,000 2,000 2,000 Location TEXAS LOUISIANA OKLAHOMA TEXAS LOUISIANA ALABAMA TEXAS LOUISIANA LOUISIANA OFFSHORE PLATFORM RIGS LOUISIANA* TEXAS LOUISIANA GULF OF MEXICO LOUISIANA GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO Rig 149 72 73 125 134 136 157 161 163 203 205 206 100 105 107 201 202 204 Optimum Depth Rig Type Drawworks: Horsepower 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 Self-Erecting Tension-leg Self-Erecting Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 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 * Rig moving to Trinidad in the first quarter of fiscal 2008. 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, 2003 2004 2005 2006 2007 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) . . . . . . . . . . . . . . . . . . . . . 87 83 81% 87% 94% 99% 97% 113 157 91 11 12 51% 48% 53% 69% 65% 11 9 9 (1) A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract. 16 The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2007: 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 * Rig moved to Argentina in the first quarter of fiscal 2008. 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, 2003 2004 2005 2006 2007 Number of rigs owned at end of Period . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1)(2) . . . . . . . . . . . . . . . . . . . . . 32 26 32 39% 54% 77% 90% 90% 27 27 (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 54 of the Company’s Annual Report (Exhibit 13 to this Form 10-K) under the caption, ‘‘Management’s Discussion & Analysis of Financial Condition and Results of Operations.’’ 17 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 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 duly elected and have qualified or until their earlier resignation or removal. W. H. Helmerich, III, 84 Chairman of the Board; Director since 1949; Chairman of the Board since 1960 Hans Helmerich, 49 . . . President and Chief Executive Officer; Director since 1987; President and Chief Executive Officer since 1989 Douglas E. Fears, 58 . . . Vice President and Chief Financial Officer since 1988 Steven R. Mackey, 56 . . Vice President, Secretary and General Counsel; Secretary since 1990; Vice President and General Counsel since 1988 John W. Lindsay, 46 . . . 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. from 1997 to 2006 M. Alan Orr, 56 . . . . . . Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. since 2006; Vice President and Chief Engineer of Helmerich & Payne International Drilling Co. from 1992 to 2006 18 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 2006 2007 High Low High Low First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $32.375 39.350 39.950 30.455 $24.945 30.420 26.375 22.020 $27.650 31.000 36.570 36.760 $21.260 22.720 30.000 27.680 The Company paid quarterly cash dividends during the past two years as shown in the following table: Quarter Paid per Share Fiscal Total Payment Fiscal 2006 2007 2006 2007 First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $.04125 .04125 .04500 .04500 $.04500 .04500 .04500 .04500 $4,290,909 4,333,069 4,344,984 4,743,331 $4,654,299 4,656,468 4,660,362 4,667,309 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 November 21, 2007, there were 703 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, 2007. 19 EQUITY COMPENSATION PLAN INFORMATION Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted- average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) Plan Category Equity compensation plans approved by security holders (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,031,715 $15.8016 3,220,814 (a) (b) (c) Equity compensation plans not approved by security holders (2) . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 6,031,715 — $15.8016 — 3,220,814 (1) Includes the 1996 Stock Incentive Plan, the 2000 Stock Incentive Plan, and the 2005 Long-Term Incentive Plan of the Company. (2) The Company does not maintain any equity compensation plans that have not been approved by the stockholders. 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 34 through 105 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). All per share amounts have been adjusted as a result of a two-for-one stock split effective June 26, 2006. Five-year Summary of Selected Financial Data 2003 2004 2005 2006 2007 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 $ 504,223 — 17,873 (in thousands except per share amounts) $ 800,726 — 127,606 $ 589,056 51,516 4,359 $1,224,813 — 293,858 $1,629,658 — 449,261 0.18 0.18 1,417,770 200,000 0.04 0.04 1,406,844 200,000 1.25 1.23 1,663,350 200,000 2.81 2.77 2,134,712 175,000 4.35 4.27 2,885,369 445,000 share . . . . . . . . . . . . . . . . . . . . . . . . . . 0.16 0.16125 0.165 0.1725 0.18 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 34 through 67 of the Company’s Annual Report (Exhibit 13 to this Form 10-K) 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 7 of this Report and on, and is incorporated by reference to, the following pages of the Company’s Annual 20 Report (Exhibit 13 to this Form 10-K) 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 69 through 105 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND Page 63-65 65 65-66 66-67 67 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, 2007. 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 effective at ensuring 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) or 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the Board of Directors of the Company; and 21 (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 control 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 control over financial reporting, based on the Company’s evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2007. The Company’s independent registered public accounting firm that audited the Company’s financial statements, Ernst & Young LLP, has issued an attestation report on the Company’s internal control over financial reporting. This report appears below. 22 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders Helmerich & Payne, Inc. We have audited Helmerich & Payne, Inc.’s internal control over financial reporting as of September 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich & 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 included in the accompanying Management’s Report of Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2007, 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 as of September 30, 2007 and 2006, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2007 of Helmerich & Payne, Inc. and our report dated November 26, 2007, expressed an unqualified opinion thereon. /S/ Ernst & Young LLP Tulsa, Oklahoma November 26, 2007 23 c) Changes in Internal Control Over Financial Reporting There were no changes in the Company’s internal control over financial reporting during the Company’s fourth fiscal quarter of 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 9B. OTHER INFORMATION None. 24 PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2008, to be filed with the Commission not later than 120 days after September 30, 2007. Information required under this item with respect to executive officers under Item 404 of Regulation S-K appears under “Executive Officers of the Company” in Part I of this Form 10-K. 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 5, 2008, to be filed with the Commission not later than 120 days after September 30, 2007. 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 5, 2008, to be filed with the Commission not later than 120 days after September 30, 2007. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2008, to be filed with the Commission not later than 120 days after September 30, 2007. 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 5, 2008, to be filed with the Commission not later than 120 days after September 30, 2007. 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, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 69 Consolidated Balance Sheets at September 30, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . 70-71 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 73 Notes to Consolidated Financial Statements at September 30, 2007 . . . . . . . . . . . . . . . . . 74-105 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. 25 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. is incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K to the Securities & Exchange Commission for fiscal 2006, SEC File No. 001-04221. 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 October 11, 2007, 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, is incorporated herein by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221. *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. 26 *10.10 Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. *10.11 Form of Director Nonqualified Stock Option Agreement for the 2000 Helmerich & Payne, Inc. Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. *10.12 Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.13 Credit Agreement, dated as of July 16, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc., the several lenders from time to time party thereto, and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.14 First Amendment to Credit Agreement dated July 15, 2003, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. 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 First Amended and Restated Credit Agreement dated December 18, 2006, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Bank of Oklahoma, National Association is incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on December 20, 2006, SEC File No. 001-04221. 10.20 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies 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. 27 10.21 Credit Agreement dated December 18, 2006, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 20, 2006, SEC File No. 001-04221. 10.22 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. *10.23 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. 10.24 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. 10.25 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. *10.26 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. *10.27 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. *10.28 First Amendment to Advisory Services Agreement dated March 7, 2007, 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 March 8, 2007, SEC File No. 001-04221. *10.29 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. *10.30 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 are incorporated herein by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221. 10.31 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. 10.32 Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to the Company’s Form 8-K filed July 7, 2007, SEC File No. 001-04221. 13. The Company’s Annual Report to Shareholders for fiscal 2007. 21. List of Subsidiaries of the Company. 23.1 Consent of Independent Registered Public Accounting Firm. 28 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. 29 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized: SIGNATURES HELMERICH & PAYNE, INC. By /s/ HANS HELMERICH Hans Helmerich, President and Chief Executive Officer Date: November 28, 2007 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated: By /s/ WILLIAM L. ARMSTRONG By /s/ GLENN A. COX William L. Armstrong, Director Date: November 28, 2007 Glenn A. Cox, Director Date: November 28, 2007 By /s/ RANDY A. FOUTCH By /s/ HANS HELMERICH Randy A. Foutch, Director Date: November 28, 2007 Hans Helmerich, Director and CEO Date: November 28, 2007 By /s/ W. H. HELMERICH, III By /s/ EDWARD B. RUST, JR. W. H. Helmerich, III, Director Date: November 28, 2007 Edward B. Rust, Jr., Director Date: November 28, 2007 By /s/ PAULA MARSHALL By /s/ JOHN D. ZEGLIS Paula Marshall, Director Date: November 28, 2007 John D. Zeglis, Director Date: November 28, 2007 By /s/ DOUGLAS E. FEARS By /s/ GORDON K. HELM Douglas E. Fears (Principal Financial Officer) Date: November 28, 2007 Gordon K. Helm (Principal Accounting Officer) Date: November 28, 2007 30 I, Hans Helmerich, certify that: CERTIFICATION 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 (the Company’s fourth fiscal quarter in the case of an annual report) 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 functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the 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: November 28, 2007 /s/ Hans Helmerich Hans Helmerich President and Chief Executive Officer 31 I, Douglas E. Fears, certify that: CERTIFICATION 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 (the Company’s fourth fiscal quarter in the case of an annual report) 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 functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the 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: November 28, 2007 /s/ Douglas E. Fears Douglas E. Fears Vice President and Chief Financial Officer 32 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 ended September 30, 2007 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: November 28, 2007 /s/ Douglas E. Fears Douglas E. Fears Vice President and Chief Financial Officer Date: November 28, 2007 33 Management’s Discussion & Analysis of Financial Condition and Results of Operations Helmerich & Payne, Inc. RISK FACTORS AND FORWARD-LOOKING STATEMENTS 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, unexpected 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 7 of the Company’s Annual Report on Form 10-K are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking 34 statement made by, or on behalf of, the Company. The Company undertakes no duty to update or revise its forward-looking statements based on changes of internal estimates or expectations or otherwise. EXECUTIVE SUMMARY Helmerich & Payne, Inc. is primarily a contract drilling company which owned and operated a total of 193 drilling rigs at September 30, 2007. The Company’s contract drilling segments include the U.S. Land segment in which the Company owned 157 rigs, the Offshore segment in which the Company owned 9 offshore platform rigs, and the International Land segment in which the Company owned 27 rigs at fiscal year end. Although crude oil prices surged in 2007 and natural gas prices remained strong, the market has experienced an influx of both new and refurbished drilling rigs causing excess capacity. This excess has put pressures on the pricing in the market and is seen in the 2007 utilization percentages. However, with the Company’s emphasis on FlexRig technology and service to the customer, the response from customers is positive and the demand for the Company’s drilling rigs remains strong. In 2007, the Company reported strong financial performance including record revenue and net income. RESULTS OF OPERATIONS 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 2007 was $449.3 million ($4.27 per share), compared with $293.9 million ($2.77 per share) for 2006 and $127.6 million ($1.23 per share) for 2005. Included in the Company’s net income were 35 after-tax gains from the sale of investment securities of $40.2 million ($0.38 per share) in 2007, $12.3 million ($0.12 per share) in 2006, and $16.4 million ($0.16 per share) in 2005. Net income also includes after-tax gains from the sale of assets of $26.5 million ($0.25 per share) in 2007, $4.8 million ($0.04 per share) in 2006 and $8.7 million ($0.08 per share) in 2005. Included in net income in 2007 is an after-tax gain of $10.6 million ($0.10 per share) from involuntary conversion of long-lived assets that sustained significant damage as a result of Hurricane Katrina in 2005. 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 $0.09 per share in 2007, $0.07 per share in 2006 and $0.02 per share in 2005. Consolidated operating revenues were $1,629.7 million in 2007, $1,224.8 million in 2006, and $800.7 million in 2005. Over the three-year period, U.S. land revenues increased due to the addition of FlexRigs combined with significant increases in dayrates during 2006. The average number of U.S. land rigs available was 134 rigs in 2007, 96 rigs in 2006 and 90 rigs in 2005. U.S. land rig utilization for the Company was 97 percent in 2007, 99 percent in 2006 and 94 percent in 2005. Revenue in the Offshore segment decreased in 2007 after increasing in 2006 and 2005. The demand for offshore rigs increased in the Gulf of Mexico after the hurricanes in 2005. Rig utilization for offshore rigs decreased to 65 percent in 2007 compared to 69 percent in 2006 and 53 percent in 2005. International rig revenues increased from 2005 to 2007, due to increases in dayrates as rig utilizations remained steady at 90 percent in 2007 and 2006, up from 77 percent in 2005. 36 Gains from the sale of investment securities were $65.5 million in 2007, $19.9 million in 2006, and $27.0 million in 2005. Interest and dividend income decreased to $4.2 million in 2007 from $9.8 million in 2006 and $5.8 million in 2005. The increase from 2005 to 2006 was 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 through part of 2007, the Company’s cash position decreased as new FlexRigs were constructed. Direct operating costs in 2007 were $862.3 million or 53 percent of operating revenues, compared with $661.6 million or 54 percent of operating revenues in 2006, and $484.2 million or 60 percent of operating revenues in 2005. The 2007 and 2006 expense to revenue percentage decrease from 2005 was primarily due to higher U.S. land revenue resulting from higher dayrates and increased activity. Depreciation expense was $146.0 million in 2007, $101.6 million in 2006 and $96.3 million in 2005. Depreciation expense increased over the three-year period as the Company placed into service 5 new rigs in 2004, 20 new rigs in 2006 and 45 in 2007. The Company anticipates 2008 depreciation expense to increase from 2007 as the rigs currently under construction are placed into service. (See Liquidity and Capital Resources.) Each year, management performs an analysis of the industry market conditions in each drilling segment. Based on this analysis, management determines if an impairment is required. In 2007, 2006 and 2005, no impairment was recorded. General and administrative expenses totaled $47.4 million in 2007, $51.9 million in 2006, and $41.0 million in 2005. The increases in 37 2007 and 2006 from 2005 were primarily due to recording stock- based compensation related to the adoption of SFAS 123(R) ‘‘Share- Based Payment’’ and the Company accelerating the vesting of share options held by a senior executive who retired. The affect of recording stock-based compensation is as follows: Other general and administrative expenses Stock-based compensation Acceleration of share options Total 2007 $40,391 7,010 — $47,401 2006 (in thousands) $42,121 6,941 2,811 $51,873 2005 $41,015 — — $41,015 The decrease in other general and administrative expenses from 2006 to 2007 is partly attributable to pension expense decreasing $5.6 million from 2006. The Pension Plan was frozen and benefit accruals were discontinued effective September 30, 2006, thus reducing the service cost of the Plan. This decrease is partially offset by increases in employee labor, benefits and operating costs associated with the number of employees increasing in 2007. The increase from 2005 to 2006 was the result of increases in expenses associated with employee benefits due to increases in the number of employees. Interest expense was $10.1 million in 2007, $6.6 million in 2006, and $12.6 million in 2005. The interest expense is primarily attributable to the fixed-rate intermediate debt outstanding in each year and advances on the senior credit facility in 2007. Capitalized interest was $9.4 million, $6.1 million and $0.3 million in 2007, 2006 and 2005, respectively. The increase in capitalized interest in 2006 and 2007 is attributable to the rig build program. The provision for income taxes totaled $251.0 million in 2007, $154.4 million in 2006, and $87.5 million in 2005. Effective income 38 tax rates were 36 percent in 2007, 35 percent in 2006, and 41 percent in 2005. 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 3 of the Consolidated Financial Statements for additional income tax disclosures.) The following tables summarize operations by reportable operating segment. The Offshore and International Land segments for 2006 and 2005 have been restated to reflect a change made to the reportable operating segments in the fourth fiscal quarter of 2007. This change, along with a detailed description of segment operating income, is described more fully in Note 15 to the Consolidated Financial Statements. 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 7 A N D 2 0 0 6 U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue 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 2007 2006 % Change (in thousands, except operating statistics) $1,174,956 587,825 14,024 106,107 $ 467,000 47,338 23,573 11,170 12,403 $ $ $ 157 97% $829,062 398,873 12,807 66,127 $351,255 34,414 $ 22,751 $ 10,250 $ 12,501 113 99% 41.7% 47.4 9.5 60.5 33.0 37.6% 3.6 9.0 (0.8) 38.9 (2.0) Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007 and three FlexRigs completed and ready for delivery at September 30, 2006. The Company’s U.S. Land segment operating income increased to $467.0 million in 2007 from $351.3 million in 2006. Improvement in revenue is primarily the result of increased revenue days as the increasing dayrates experienced during 2006 declined or flattened during 2007. Rig utilization decreased to 97 percent in 2007 from 99 percent in 2006. The decrease in rig utilization is primarily due to six conventional rigs being stacked by fiscal year-end. The stacked rigs target a deeper well market that softened during the last half of 2007. Average rig expense per day increased 9.0 percent as the demand for rig personnel and services continued to create cost pressures. The total number of rigs owned at September 30, 2007 was 157 compared to 113 rigs at September 30, 2006. The increase is due to 45 new FlexRigs completed and placed into service, one rig completed and ready for delivery, the sale of one conventional rig in June 2007 and the loss of one rig in a well blowout fire in 40 August 2007. Depreciation in 2007 increased 60.5 percent from 2006 due to the increase in available rigs. During 2007, 2006 and 2005, the Company announced plans to build 77 new FlexRigs for 19 exploration and production companies. Subsequent to September 30, 2007, the Company announced that an agreement had been reached with an exploration and production company to operate an additional six new FlexRigs bringing the total of the new rigs to 83. Each new rig will be operated by the Company under a minimum three-year fixed term contract. The drilling services will be performed on a daywork contract basis. During 2007, the U.S. Land segment had 48 new FlexRigs placed into service, three of which were completed at the end of fiscal 2006, and one rig was completed and ready for delivery as of September 30, 2007. In 2006, 20 new FlexRigs were placed into service. The remaining rigs are expected to be delivered by the end of the third fiscal quarter of 2008. As a result of the new FlexRigs, the Company anticipates depreciation expense to increase in fiscal 2008. During the fourth quarter of fiscal 2007, the Company’s Rig 178 was lost when the well it was drilling had a blowout. 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. Subsequent to September 30, 2007, gross insurance proceeds of approximately $8.5 million were received and a gain of approximately $4.8 million was recorded. The Company anticipates settling the insurance claim before the end of the second fiscal quarter of 2008 and expects to receive additional insurance proceeds of less than $0.5 million. 41 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 7 A N D 2 0 0 6 OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue 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 2007 2006 % Change (in thousands, except operating statistics) $123,148 85,556 4,824 10,687 $ 22,081 2,141 $ 34,469 $ 21,564 $ 12,905 9 65% $154,543 105,133 6,144 11,401 $ 31,865 2,743 $ 38,728 $ 24,041 $ 14,687 9 69% (20.3)% (18.6) (21.5) (6.3) (30.7) (21.9)% (11.0) (10.3) (12.1) — (0.6) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses and exclude the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in the Company’s Offshore segment decreased 30.7 percent from 2006 to 2007. Operator decisions to go on standby caused revenue and expenses to decline after the segment experienced increased activity in 2006 following the hurricanes in 2005. Currently, the Company has five of its nine platform rigs working and two in negotiations for work that, if contracted, would start in 2008. One rig is currently in the yard undergoing capital improvement and is expected to return to work with a contract in the second fiscal quarter of 2009. The ninth rig is currently being transported and is expected to start operations in Trinidad during the second fiscal quarter of 2008. During the fourth fiscal quarter of 2006, the Company signed an option agreement to sell two offshore rigs that were idle. The purchase option was exercised and the transaction completed in the 42 second fiscal quarter of 2007. The two rigs were classified as assets held for sale in the Company’s Consolidated Financial Statements and, as such, 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. The rig was removed from service in the fourth fiscal quarter of 2005 until the fourth fiscal quarter of 2007, when it returned to service. The rig was insured at a value that approximated replacement cost. 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. In fiscal 2007, insurance proceeds of approximately $16.3 million were received resulting in a gain of approximately $16.7 million. Capital costs to rebuild the rig were capitalized and are being depreciated in accordance with the accounting policy described in Critical Accounting Policies and Estimates. Additional claims have been submitted and future proceeds will be recorded as gain from involuntary conversion. The Company expects to settle this claim in 2008 and estimates additional proceeds to range from $5 million to $10 million. 43 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 7 A N D 2 0 0 6 INTERNATIONAL LAND OPERATIONS (in thousands, except operating statistics) 2007 2006 % Change Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue 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 $320,283 188,086 3,236 23,782 $105,179 8,886 $ 31,465 $ 16,708 $ 14,757 27 90% $230,829 155,766 3,274 19,471 $ 52,318 8,812 $ 23,404 $ 14,806 $ 8,598 27 90% 38.8% 20.7 (1.2) 22.1 101.0 0.8% 34.4 12.8 71.6 — — Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses and exclude the effects of currency revaluation expense. Segment operating income for the Company’s International Land segment increased 101.0 percent from 2006 to 2007 due to dayrate increases in several foreign markets with the most significant increase occurring in Venezuela. Segment operating income also benefited from a new FlexRig being added to the international fleet at the end of fiscal 2006. Rig utilization for international land operations averaged 90 percent in both 2007 and 2006. Direct operating expenses increased in 2007 primarily due to inflationary pressures in the oil service sector and contractual cost increases. The Ecuadorian government continues to negotiate with the Company’s customers to resolve contract disputes created by a recent government decree. The decree modified the original contracts for splitting profits on oil production. If this continues without resolution, the Company anticipates that up to seven rigs could become idle in Ecuador in the second quarter of fiscal 2008. Should 44 this situation occur, the Company, at this time, is unable to predict the length of time that the rigs would remain idle. 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 7 A N D 2 0 0 6 REAL ESTATE Operating revenues Direct operating expenses Depreciation Segment operating income 2007 $11,271 3,808 2,456 $ 5,007 2006 (in thousands) $10,379 3,524 2,444 $ 4,411 % Change 8.6% 8.1 0.5 13.5 Segment operating income in the Company’s Real Estate segment increased 13.5 percent from 2006 to 2007. The segment experienced increases in revenues as average occupancy rates increased. 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: Revenue 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 at September 30, 2006. The Company’s U.S. Land segment operating income increased to $351.3 million in 2006 from $164.7 million in 2005. As crude oil and natural gas prices reached historically high levels, increases in 45 U.S. land rig activity and higher dayrates experienced during 2005 continued in 2006 resulting in improvements in revenue and margin per day. 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. 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 OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue 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) $154,543 105,133 6,144 11,401 $ 31,865 2,743 $ 38,728 $ 24,041 $ 14,687 9 69% $106,296 69,664 3,980 10,639 $ 22,013 2,122 $ 29,228 $ 15,967 $ 13,261 11 53% 45.4% 50.9 54.4 7.2 44.8 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 and currency revaluation expense. Segment operating income in the Company’s Offshore segment increased 44.8 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. 46 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 LAND OPERATIONS (in thousands, except operating statistics) 2006 2005 % Change Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue 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 $230,829 155,766 3,274 19,471 $ 52,318 8,812 $ 23,404 $ 14,806 $ 8,598 27 90% $156,105 118,959 2,408 20,070 $ 14,668 7,491 $ 19,332 $ 14,039 $ 5,293 26 77% 47.9% 30.9 36.0 (3.0) 256.7 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 currency revaluation expense. Segment operating income for the Company’s International Land segment increased 256.7 percent from 2005 to 2006 due to higher rig activity and dayrates. Rig utilization for international land operations averaged 90 percent in 2006, compared with 77 percent in 2005. During 2006, one new FlexRig was added to the international land 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 $10,379 3,524 2,444 $ 4,411 2005 (in thousands) $10,688 3,622 2,352 $ 4,714 % Change (2.9)% (2.7) 3.9 (6.4) Segment operating income in the Company’s Real Estate segment decreased 6.4 percent from 2005 to 2006. The segment experienced decreases in reimbursements associated with property taxes and 47 increases in depreciation due to capital expenditures for leasehold and building improvements. LIQUIDIT Y AND CAPITAL RESOURCES The Company’s capital spending was $894.2 million in 2007, $528.9 million in 2006, and $86.8 million in 2005. Net cash provided from operating activities for those same periods was $561.1 million in 2007, $296.4 million in 2006 and $212.2 million in 2005. The Company’s 2008 capital spending estimate is approximately $375 million, a decrease from the budgeted $750 million in 2007, due to completing construction of currently contracted new FlexRigs. Construction of the contracted new FlexRigs is expected to be completed by the end of the third fiscal quarter of 2008. 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 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. 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 (in thousands) $ 8,592 139,848 $148,440 2005 $3,000 2,000 $5,000 2007 — — — $ $ 48 The Company manages a portfolio of marketable securities that, at the close of 2007, had a market value of $457.5 million. The Company’s investments in Atwood Oceanics, Inc. (‘‘Atwood’’) and Schlumberger, Ltd. made up 93 percent of the portfolio’s market value on September 30, 2007. 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. The Company currently owns 4,000,000 shares or approximately 12.6 percent of the outstanding shares of Atwood. The Company generated cash proceeds from the sale of portfolio securities of $73.4 million in 2007, $28.2 million in 2006, and $46.7 million in 2005. 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: 2007 Proceeds from the sale of portfolio securities $ 73,405 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 48,321 2006 (in thousands) $ 28,245 (6,093) 91,563 2005 $ 46,700 16,839 2,000 Statements of Cash Flows $127,819 $113,715 $ 65,539 In 2007, proceeds were primarily from the sale of 1,012,500 shares of Schlumberger, Ltd. Proceeds were primarily used to fund capital expenditures. 49 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. In July 2004, Atwood filed a Registration Statement covering all 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 a portion 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. The Company has historically been a long-term holder of investment securities. However, circumstances may arise such as significant 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 and 2007, the Company purchased 2,007,100 shares of Company common stock at an aggregate cost of $46.0 million. The Company’s proceeds from asset sales totaled $51.6 million in 2007, $11.8 million in 2006 and $29.0 million in 2005. In 2007, one U.S. land rig and two offshore rigs were sold generating $36.7 million in proceeds. Income from asset sales in 2007 totaled $41.7 million. 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 U.S. land rigs which generated a gain of approximately $9.0 million and proceeds of approximately $23.3 million. The rigs sold in each year were idle at the time of the sales and, with the Company’s emphasis on 50 FlexRig technology, the Company took advantage of the opportunity to sell older rigs. In each year the Company also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business. In the fourth fiscal quarter of 2006, the Company received approximately $3.0 million in insurance proceeds from damages sustained to the Company’s offshore Rig 201 during Hurricane Katrina. In 2007, the Company received additional insurance proceeds of approximately $16.3 million. In conjunction with removing the net book value of damaged equipment lost in the hurricane, the Company recorded a gain from involuntary conversion of approximately $16.7 million. The proceeds, shown in the Consolidated Statements of Cash Flows under investing activities, were used to rebuild the rig. Those costs were capitalized and the rig returned to work in the fourth fiscal quarter of 2007. Since March 2005, the Company has announced contracts to build and operate 77 new FlexRig3s and FlexRig4s for 19 exploration and production companies. Subsequent to September 30, 2007, the Company announced that an agreement had been reached with an exploration and production company to operate an additional six new FlexRigs, bringing the total of the new rigs to 83. Each agreement has a minimum fixed contract term of at least three years. The drilling services are performed on a daywork contract basis. Through fiscal 2007, 70 rigs were completed for delivery, and 69 of the 70 rigs began field operations by September 30, 2007. In 2006 the Company experienced delivery delays associated with labor and equipment shortages. Late-delivery contractual liquidated damage payments were incurred in 2006 and 2007 but they have had an immaterial impact on revenues and margins. Although the rig 51 delivery schedule was revised in August 2006, the Company was successful in deploying 48 of the 69 new FlexRigs to field operations in fiscal 2007. The rig construction project is currently ahead of the revised schedule. The remaining rigs are expected to be completed by the end of the third fiscal quarter of 2008. The total estimated construction cost of all 83 rigs is currently $1.3 billion. Approximately $0.7 billion was incurred in fiscal 2007 and approximately $0.4 billion was incurred in fiscal 2006 for construction of the new FlexRigs. Construction cost estimates were revised in August 2006 and the total costs incurred to date have remained within those estimates. The Company has $175 million intermediate-term unsecured debt obligations with staged maturities from August, 2009 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 December 18, 2006, the Company entered into an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility. The Company has the option to borrow at the prime rate for maturities of less than 30 days but anticipates the majority of all of the borrowings over the life of the new facility will accrue interest at a spread over LIBOR. The Company pays a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee are determined according to a scale based on the ratio of the Company’s total debt to total capitalization. The LIBOR spread ranges 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 was .35 percent and the commitment fee was .075 percent per annum. Financial 52 covenants in the facility require the Company to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The new facility contains 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. At closing, the Company transferred two letters of credit totaling $20.9 million to the facility that remained outstanding at September 30, 2007. As of September 30, 2007, the Company had $270 million borrowed against the facility. The advances bear interest ranging from 5.48 percent to 6.15 percent. At September 30, 2007, the Company was in compliance with all debt covenants. In conjunction with the $400 million senior unsecured credit facility, the Company entered into an agreement with a single bank to amend and restate the previous unsecured line of credit from $50 million to $5 million. Pricing on the amended line of credit is prime minus 1.75 percent. The covenants and other terms and conditions are similar to the aforementioned senior credit facility except that there is no commitment fee. At September 30, 2007, the Company had no outstanding borrowings against this line. As of September 30, 2006, the Company had four outstanding, unsecured notes payable to a bank in Venezuela totaling $3.7 million denominated in a foreign currency. The interest rate of the notes was 13 percent with a 60 day maturity. The notes and interest were paid in full during fiscal 2007. Subsequent to September 30, 2007, the Company obtained letters of credit totaling approximately $3.1 million to secure importation bonds in Trinidad and Tobago associated with moving a rig into that country. 53 The Company’s operating cash requirements and estimated capital expenditures, including rig construction, for fiscal 2008 will be funded through current cash, cash provided from operating activities, funds available under the credit facilities and possibly, sales of available-for-sale securities. Current ratios for September 30, 2007 and 2006 were 2.2 and 1.6, respectively. The increase in current ratio is primarily due to increases in accounts receivable and other current assets and a decrease in the current portion of long-term debt. The debt to total capitalization ratio was 20 percent and 14 percent at September 30, 2007 and 2006, respectively. The increase is due to additional borrowing in 2007 to finance construction of the new FlexRigs. During 2007, the Company paid a dividend of $0.18 per share, or a total of $18.6 million, representing the 35th consecutive year of dividend increases. STOCK PORTFOLIO HELD BY THE COMPANY September 30, 2007 Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total Number of Shares Cost Basis Market Value (in thousands, except share amounts) 4,000,000 1,137,500 $74,210 $306,240 9,035 14,663 119,438 31,813 $97,908 $457,491 MATERIAL COMMITMENTS The Company has no off balance sheet arrangements other than operating leases discussed below. The Company’s contractual 54 obligations as of September 30, 2007, are summarized in the table below: Payments due by year Contractual Obligations Total 2008 2009 2010 2011 2012 After 2012 Long-term debt (a) $445,000 $ — $25,000 $ — $270,000 $75,000 $75,000 Operating leases (b) Purchase obligations (b) 8,154 82,722 3,982 82,722 2,958 1,214 — — — — — — — — Total Contractual Obligations $535,876 $86,704 $27,958 $1,214 $270,000 $75,000 $75,000 (in thousands) (a) See Note 2 ‘‘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. In 2007, the Company contributed $2.7 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 2008. However, the Company does expect to make discretionary contributions to fund distributions of at least $3.0 million in 2008. Future contributions beyond 2008 are difficult to estimate due to multiple variables involved. CRITICAL ACCOUNTING POLICIES AND ESTIMATES 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 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 55 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, pension, stock-based compensation, and revenue recognition. Other significant accounting policies are summarized in Note 1 in the notes to the Consolidated Financial Statements. Property, Plant and Equipment 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 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. 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. Impairment of Long-lived Assets 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 56 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. 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. Use of different assumptions could result in an impairment charge different from that reported. Self-Insurance Accruals 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 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 coverage with deductibles as high as $5 million. Insurance is also purchased on rig properties and deductibles are typically $1 million per occurrence. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon the Company’s 57 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. Pension Costs and Obligations 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’s discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was raised as of September 30, 2007 to reflect changes in the market conditions for high-quality fixed-income investments. 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 2008 to decrease from 2007. Stock-Based Compensation Historically, the Company has granted stock-based awards to key employees and non-employee directors as 58 part of their compensation. Effective October 1, 2005, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), Share-Based Payment (‘‘SFAS 123(R)’’), using the modified-prospective transition method, which requires that the fair value of unvested stock options be recognized in the income statement, over the remaining vesting period. The Company estimates the fair value of all stock option awards as of the date of grant by applying the Black-Scholes option-pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and risk-free interest rate. Expected volatilities were estimated using the historical volatility of the Company’s stock, based upon the expected term of the option. The Company was not aware of information in determining the grant date fair value that would have indicated that future volatility would be expected to be significantly different than historical volatility. The expected term of the option was derived from historical data and represents the period of time that options are estimated to be outstanding. The risk-free interest rate for periods within the estimated life of the option was based on the U.S. Treasury Strip rate in effect at the time of the grant. The fair value of each award is amortized on a straight-line basis over the vesting period for awards granted to employees. Stock- based awards granted to non-employee directors are expensed immediately upon grant. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant. The Company amortizes the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2007, unrecognized compensation cost related to 59 unvested restricted stock options was $4.6 million. The cost is expected to be recognized over a weighted-average period of 3.3 years. Prior to the adoption of SFAS 123(R), the Company accounted for share-based compensation under the ‘‘intrinsic value method’’ and the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this method, no share-based compensation expense associated with the Company’s stock options was recognized in periods prior to fiscal 2006 as all options were granted with an exercise price no less than the market value of the underlying common stock on the date of grant. Revenue Recognition 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. NEW ACCOUNTING STANDARDS In September 2006, the Financial Accounting Standards Board (‘‘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 60 underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position. This statement was adopted by the Company for the fiscal year ending September 30, 2007. As discussed in Note 9 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 had effectively reflected the funded status of the plan in the Consolidated Balance Sheet; therefore, SFAS 158 had no impact on the Consolidated 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. The guidance outlined in SAB 108 was effective for the Company in fiscal 2007 and is consistent with the historical practices the Company uses for assessing such matters when circumstances have required such an evaluation. In June, 2006, the 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 does not believe the adoption of this interpretation will have a material impact on the Consolidated Financial Statements. 61 In September 2006, the 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 the Consolidated Financial Statements. In February 2007, the FASB issued SFAS No. 159, The Fair Value of Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS No 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis and, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. At the effective date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. The Company is currently assessing the impact, if any, of SFAS No. 159 on the Consolidated Financial Statements. 62 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Foreign Currency Exchange Rate Risk The Company has operations in several South American countries and Africa. With the exception of Argentina and Venezuela, the Company’s exposure to currency valuation losses is usually immaterial due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars. In Argentina, the Company’s exposure is limited by the fact that the exchange rate between the U.S. dollar and the Argentine peso has stayed within a narrow range for the last four years. 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. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation has been reduced by these amounts. 63 On June 7, 2007, the Company began the process to make 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 $8.3 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 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. At September 30, 2007, the Company had a $25.6 million cash balance denominated in bolivares exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2008 activity levels are similar to fiscal 2007 and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $3.5 million to $6.4 million. The Company has an agreement with the Venezuelan state petroleum company whereby a portion of the Company’s dollar-based invoices 64 are paid 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, 2007, the Company had a net receivable from PDVSA of $49.7 million of which $12.0 million was 90 days old or older. At November 1, 2007, such receivable balance had increased to approximately $50.3 million, of which approximately $14.4 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. 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 65 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 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 Company has reduced the impact of fluctuations in interest rates by maintaining a portion of its debt portfolio in fixed-rate debt. At September 30, 2007, the amount of the Company’s fixed-rate debt was approximately 39 percent of total debt. The following tables provide information as of September 30, 2007 and 2006 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 7 (dollars in thousands) 2008 2009 2010 2011 2012 After 2012 Total Fair Value 9/30/07 Fixed Rate Debt Average Interest Rate Variable Rate Debt $ $ — $25,000 $ — $ — $75,000 $75,000 $175,000 $182,269 — 5.9% — — 6.5% 6.6% 6.5% — $ — $ — $270,000 $ — $ — $270,000 $270,000 Average Interest Rate (a) — — — — — — (a) 66 (a) Advances bear interest rates ranging from 5.48% to 6.15% 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 at 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 (b) $ 3,721 Average Interest Rate 13.0% (b) Denominated in a foreign currency $ 3,721 $ 3,721 13.0% Equity Price Risk On September 30, 2007, the Company had a portfolio of securities with a total market value of $457.5 million. The total market value of the portfolio of securities was $336.1 million at September 30, 2006. The Company’s investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up 93 percent of the portfolio’s market value at September 30, 2007. Although the Company sold portions of its positions in Schlumberger in 2007, 2006 and 2005, and Atwood in the first fiscal quarter of 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. 67 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, 2007 and 2006, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2007. 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, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2007, 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, 2007, based on criteria established in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 26, 2007 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 November 26, 2007 68 Consolidated Statements of Income Years Ended September 30, 2007 2006 2005 OPERATING REVENUES Drilling – U.S. Land Drilling – Offshore Drilling – International Land Real Estate OPERATING COSTS AND EXPENSES Operating costs, excluding depreciation Depreciation General and administrative Gain from involuntary conversion of long-lived assets Income from asset sales Operating income 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) $1,174,956 $ 829,062 $ 527,637 123,148 320,283 11,271 154,543 230,829 10,379 106,296 156,105 10,688 1,629,658 1,224,813 800,726 862,254 146,042 47,401 (16,661) (41,697) 661,563 101,583 51,873 — 484,231 96,274 41,015 — (7,492) (13,550) 997,339 807,527 607,970 632,319 417,286 192,756 4,234 (10,126) 65,458 (1,532) 58,034 690,353 250,984 9,892 9,834 (6,644) 19,866 639 5,809 (12,642) 26,969 (235) 23,695 19,901 440,981 154,391 7,268 212,657 87,463 2,412 $ 449,261 $ 293,858 $ 127,606 $ $ 4.35 4.27 $ $ 2.81 2.77 $ $ 1.25 1.23 103,338 105,128 104,658 106,091 102,174 104,066 69 Consolidated Balance Sheets ASSETS CURRENT ASSETS: Cash and cash equivalents Short term investments September 30, 2007 2006 (in thousands) Accounts receivable, less reserve of $2,957 in 2007 and $2,007 in 2006 Inventories Deferred income taxes Assets held for sale Prepaid expenses and other Total current assets $ 89,215 $ 33,853 352 339,819 29,145 11,559 — 28,874 498,964 48,673 289,479 26,165 10,168 4,234 16,119 428,691 INVESTMENTS 223,360 218,309 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. 2,651,680 1,911,039 214,642 59,467 131,482 3,057,271 904,655 2,152,616 220,603 58,286 113,788 2,303,716 820,582 1,483,134 10,429 4,578 $2,885,369 $2,134,712 70 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, 2007 2006 (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 Accumulated other comprehensive income Less treasury stock, 3,572,961 shares in 2007 and 3,188,760 shares in 2006, at cost Total shareholders’ equity $ — $ 3,721 124,556 102,056 — 226,612 445,000 363,534 34,707 843,241 10,706 — 143,146 1,645,766 75,885 1,875,503 59,987 1,815,516 138,750 97,077 25,000 264,548 175,000 269,919 43,353 488,272 10,706 — 135,500 1,215,127 69,645 1,430,978 49,086 1,381,892 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $2,885,369 $2,134,712 The accompanying notes are an integral part of these statements. 71 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, 2004 107,058 $10,706 $ 80,113 $ 828,763 $ — $36,252 6,167 $(41,724) $ 914,110 (in thousands, except per share amounts) 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 $10.2 million Repurchase of common stock Stock-based compensation Balance, September 30, 2006 Comprehensive Income: Net income Other comprehensive income (loss): Unrealized gains on available-for-sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Cash dividends ($.18 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $1.5 million Repurchase of common stock Stock-based compensation Balance, September 30, 2007 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 4,510 127,606 14,708 (3,416) 11,292 138,898 2,682 67 16,455 — (16,989) 25,358 15,153 26 (25,202) 1,079,238 293,858 17,591 4,510 22,101 315,959 — (18,111) 12,372 134 10 (68) (18,111) (1,335) 6,353 1,215,127 — 69,645 3,189 1,325 (30,169) 12,851 (30,169) 9,752 (49,086) 1,381,892 449,261 (18,622) (2,930) 9,170 (298) 4,958 449,261 (2,930) 9,170 6,240 455,501 (18,622) 3,802 107,058 10,706 (66) 6,019 12,851 9,752 135,500 (1,156) 1,792 7,010 107,058 $10,706 $143,146 $1,645,766 $ — $75,885 682 (15,859) 1,792 (15,859) 7,010 3,573 $(59,987) $1,815,516 The accompanying notes are an integral part of these statements. 72 Consolidated Statements of Cash Flows Years Ended September 30, 2007 2006 2005 OPERATING ACTIVITIES: Net income Adjustments to reconcile income to net cash provided by operating activities: Depreciation Provision for bad debt Equity in income of affiliate before income taxes Stock-based compensation Gain on sale of investment securities Gain from involuntary conversion of long-lived assets 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) $ 449,261 $ 293,858 $127,606 146,042 1,030 (15,954) 7,010 (65,320) (16,661) (41,697) 82,294 1,000 (53,773) (2,980) (18,606) 73,780 5,299 6,107 4,235 101,583 250 (11,723) 9,752 (19,730) — (7,492) 3,504 (987) 96,274 530 (3,891) 26 (26,969) — (13,550) 38,014 (879) (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 Net cash provided by operating activities 561,067 296,390 212,238 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 Decrease in long-term debt Proceeds from line of credit Payments on line of credit Increase (decrease) 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. 73 (894,214) (528,905) 51,568 16,257 — 127,819 (698,570) (17,621) (3,721) (25,000) 1,490,000 (1,220,000) (17,430) (18,638) 3,802 1,473 192,865 55,362 33,853 89,215 $ 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 $ 33,853 (86,805) 28,992 — (5,000) 65,539 2,726 — — — — — — (16,866) 25,358 — 8,492 223,456 65,296 $288,752 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 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, fiscal years 2006 and 2005 operating revenues for Drilling – Offshore and for Drilling – International Land have been restated to reflect a change in those two segments more fully described in Note 15. 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 gains included in direct operating costs totaled $1.0 million in 2007 and losses included in direct operating costs totaled $0.3 million and $0.8 million in 2006 and 2005, 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. 74 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 2007, 2006, and 2005 was $9.4 million, $6.1 million, and $0.3 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. 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. 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 for moving funds into, 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. At September 30, 2007, there were no negative book cash balances. RESTRICTED CASH AND CASH EQUIVALENTS The Company had restricted cash and cash equivalents of $8.2 million and $4.3 million at September 30, 2007 and 2006, respectively. Restricted cash is primarily for the purpose of potential insurance claims in the Company’s wholly-owned captive insurance company. Of the total at September 30, 2007, $2.0 million is from the initial capitalization of the captive and management has elected to restrict an additional $5.5 million. The remaining $0.7 million restricted cash is for indemnification on outstanding importation bonds. The restricted amounts are primarily invested in short-term money market securities. The restricted cash and cash equivalents are reflected in the balance sheet as follows (in thousands): September 30, Other current assets Other assets 2007 $6,203 $2,000 2006 $2,273 $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. 75 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 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 2007 $8,873 $1,474 2006 (in thousands) $8,538 $1,219 2005 $7,606 $1,162 At September 30, 2007, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2008 2009 2010 2011 2012 Thereafter Total Amount $ 7,286 5,488 4,544 3,590 2,328 5,559 $28,795 Leasehold improvement allowances are capitalized and amortized over the lease term. 76 At September 30, 2007 and 2006, the cost and accumulated depreciation for real estate properties were as follows: September 30, Real estate properties Accumulated depreciation 2007 2006 $59,467 (33,886) $25,581 $58,286 (31,664) $26,622 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. 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 12.6 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 in Atwood was $306.2 million and $179.9 million at September 30, 2007 and 2006, respectively. Retained earnings at September 30, 2007 and 2006 includes approximately $41.5 million and $31.6 million, respectively, of undistributed earnings of Atwood. 77 Summarized financial information of Atwood is as follows: September 30, Gross revenues Costs and expenses Net income Helmerich & Payne, Inc.’s equity in net income, net of income taxes Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity 2007 $403,037 264,013 $139,024 2006 (in thousands) $276,625 190,503 $ 86,122 2005 $176,156 149,785 $ 26,371 $ 9,892 $ 7,268 $ 2,412 $216,179 501,545 57,630 44,239 $615,855 $147,673 446,156 61,365 73,570 $458,894 $ 93,283 403,641 56,159 78,268 $362,497 Helmerich & Payne, Inc.’s investment $ 74,210 $ 58,256 $ 46,533 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 78 prior periods. Under this transition method, compensation expense associated with stock options recognized in fiscal 2007 and 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 5 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 Financial Accounting Standards Board (‘‘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 was adopted by the Company for the fiscal year ending September 30, 2007. As discussed further in Note 9, the Company’s pension plan was frozen on September 30, 2006. As a result of the plan being frozen, the Company had effectively reflected the funded status of the plan in the Consolidated Balance Sheets; therefore, SFAS 158 had no impact on the Consolidated 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. The guidance outlined in SAB 108 was effective for the Company in fiscal 2007 and is consistent with the historical practices the Company uses for assessing such matters when circumstances have required such an evaluation. In June 2006, the 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 does not believe the adoption of this interpretation will have a material impact on the Consolidated Financial Statements. In September 2006, the 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 79 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 the Consolidated Financial Statements. In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. At the effective date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. The Company is currently assessing the impact, if any, of SFAS No. 159 on the Consolidated Financial Statements. NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 2007 and 2006, the Company had $445 million and $200 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table: Maturity Date Interest Rate 2007 2006 September 30, Fixed-rate debt: August 15, 2007 August 15, 2009 August 15, 2012 August 15, 2014 Senior credit facility: December 18, 2011 5.51% 5.91% 6.46% 6.56% 5.48%-6.15% Less long-term debt due within one year Long-term debt $ — $ 25,000,000 25,000,000 75,000,000 75,000,000 270,000,000 $445,000,000 — $445,000,000 25,000,000 75,000,000 75,000,000 — $200,000,000 (25,000,000) $175,000,000 The terms of the fixed-rate 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. On December 18, 2006, the Company entered into an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility. While the Company has the option to borrow at the prime rate for maturities of less than 30 days, the Company anticipates that the majority of all the borrowings over the life of the facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). The Company 80 pays a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of the Company’s total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. At September 30, 2007, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. Financial covenants in the facility require the Company to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The new facility contains 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. At closing, the Company transferred two letters of credit totaling $20.9 million to the facility that remained outstanding at September 30, 2007. As of September 30, 2007, the Company had $270 million borrowed against the facility with $109.1 million left available to borrow. The advances bear interest ranging from 5.48 percent to 6.15 percent. Subsequent to September 30, 2007, the outstanding balance was reduced by $10 million. At September 30, 2007, the Company was in compliance with all debt covenants. In conjunction with the $400 million senior unsecured credit facility, the Company entered into an agreement with a single bank to amend and restate the previous unsecured line of credit from $50 million to $5 million. Pricing on the amended line of credit is prime minus 1.75 percent. The covenants and other terms and conditions are similar to the aforementioned senior credit facility except that there is no commitment fee. At September 30, 2007, the Company had no outstanding borrowings against this line. Subsequent to September 30, 2007, the Company obtained letters of credit with a financial institution totaling approximately $3.1 million to secure importation bonds in Trinidad and Tobago associated with moving a rig into that country. 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. The notes and interest were paid in full during fiscal 2007. 81 NOTE 3 INCOME TAXES The components of the provision for income taxes are as follows: Years Ended September 30, 2007 Current: Federal Foreign State Deferred: Federal Foreign State $125,169 31,552 11,969 168,690 74,389 1,528 6,377 82,294 2006 (in thousands) $136,370 4,304 10,213 150,887 10,252 (7,776) 1,028 3,504 Total provision $250,984 $154,391 2005 $39,139 8,185 2,125 49,449 31,573 4,863 1,578 38,014 $87,463 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 2007 $579,589 110,764 $690,353 2006 (in thousands) $389,595 51,386 $440,981 2005 $195,978 16,679 $212,657 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. 82 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 Financial accruals Other Total deferred tax assets Valuation allowance Net deferred tax assets Net deferred tax liabilities 2007 2006 (in thousands) $303,915 46,501 25,413 1,415 377,244 1,689 2,884 26,926 21,995 6 53,500 28,231 25,269 $220,851 48,593 19,350 51 288,845 8,441 3,384 33,029 17,260 9 62,123 33,029 29,094 $351,975 $259,751 Reclassifications have been made to the fiscal 2006 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 is impacted by foreign currency remeasurement. As of September 30, 2007 the Company had foreign net operating loss carryforwards for income tax purposes of $3.9 million, and foreign tax credit carryforwards of approximately $25.7 million which will expire in years 2010 through 2015. The valuation allowance is primarily attributable to foreign net operating loss carryforwards and foreign tax credit carryforwards for which it is more likely than not that these will not be utilized. Effective income tax rates as compared to the U.S Federal income tax rate are as follows: Years Ended September 30, 2007 2006 2005 U.S. Federal income tax rate Effect of foreign taxes State income taxes Effective income tax rate 35% (1) 1 35% 35% 3 3 41% 35% (1) 2 36% 83 NOTE 4 SHAREHOLDERS’ EQUITY 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, 2007, the Company had 103,484,943 outstanding common stock purchase rights (‘‘Rights’’) pursuant to 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 entitles 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. NOTE 5 STOCK-BASED COMPENSATION The Company has several plans providing for stock based awards to employees and to non-employee directors from which stock grants have been made. On March 1, 2006, at the Annual Meeting of Stockholders, the 2005 Long-Term Incentive Plan (the Plan) was approved. Upon approval of the Plan, no further grants could be made from those prior plans. However, awards outstanding in those prior plans remain subject to the terms and conditions of those plans. The provisions of 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. 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. 84 The Company has the right to satisfy option exercises from treasury shares and from authorized but unissued shares. During fiscal 2007, the Company purchased 681,900 shares at an aggregate cost of $15.9 million. 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. 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. 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. 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 2007 and 2006 is as follows (in thousands, except per share amounts): September 30, Compensation expense Stock options Restricted stock After-tax stock based compensation Per basic share Per diluted share Cash received from exercise of stock options 2007 2006 $5,643 1,367 $7,010 $4,346 $ $ .04 .04 $3,802 $ 8,714 1,038 $ 9,752 $ 6,046 $ $ .06 .06 $12,372 85 Benefits of tax deductions in excess of recognized compensation cost of $1.5 million and $10.2 million are reported as a financing cash flow in the Consolidated Condensed Statements of Cash Flow for fiscal 2007 and 2006, respectively. 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 that is included in the table above. 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 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) 2007 4.6% 35.9% .7% 5.5 2006 4.5% 36.9% .5% 5.2 2005 4.2% 40.3% 1.0% 5.0 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. 86 The following summary reflects the stock option activity for the Company’s common stock and related information for 2007, 2006, and 2005 (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2007 2006 2005 Weighted-Average Exercise Price $14.24 26.90 12.77 28.57 $15.80 $12.70 Options 5,619 731 (298) (20) 6,032 4,335 3,221 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 Weighted-Average Exercise Price $11.02 16.01 9.79 13.61 $12.29 $11.37 Options 8,914 926 (3,222) (130) 6,488 4,054 1,510 Restricted stock awards granted under the 2005 Long-Term Incentive Plan are counted against the limit of shares available for issuance under such plan at the rate of 1.8 shares for each share granted. The following table summarizes information about stock options at September 30, 2007 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $6.3975 to $9.4178 $11.3318 to $16.0100 $26.8950 to $30.2375 $6.3975 to $30.2375 Options 874 3,843 1,315 6,032 Weighted-Average Remaining Life Weighted-Average Exercise Price 1.7 5.3 8.7 5.5 $ 8.02 $13.26 $28.41 $15.80 Options 874 3,280 181 4,335 Weighted-Average Exercise Price $ 8.02 $13.01 $29.80 $12.70 At September 30, 2007, the weighted-average remaining life of exercisable stock options was 4.5 years and the aggregate intrinsic value was $87.3 million with a weighted-average exercise price of $12.70 per share. The number of options expected to vest at September 30, 2007 was 5,983,240 with an aggregate intrinsic value of $102.4 million and a weighted-average exercise price of $15.72 per share. As of September 30, 2007, the unrecognized compensation cost related to the stock options was $10.6 million. That cost is expected to be recognized over a weighted-average period of 2.5 years. The weighted-average fair value of options granted during 2007, 2006 and 2005 was $10.36, $11.40 and $6.09, respectively. The total intrinsic value of options exercised during 2007, 2006 and 2005 was $5.8 million, $34.9, and $41.3 million, respectively. The fair value of shares vested during 2007 and 2006 was $5.4 million and $9.1 million, respectively. 87 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 had applied the fair value recognition provisions of SFAS No. 123, ‘‘Accounting for Stock-Based Compensation’’ (in thousands, except per share amounts): 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 $127,606 16 (3,563) $124,059 $ $ $ $ 1.25 1.21 1.23 1.19 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, 2007, there was $4.6 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 3.3 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, 2007, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2007, 2006 and 2005 is as follows (share amounts in thousands): Outstanding at October 1, Granted Vested Forfeited/Expired Outstanding on September 30, Shares 213 27 — — 240 2007 Weighted-Average Grant Date Fair Value per Share $29.57 26.90 — — $29.27 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 88 NOTE 6 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 2007 103,338 1,790 105,128 2006 (in thousands) 104,658 1,433 106,091 2005 102,174 1,892 104,066 At September 30, 2007, options to purchase 593,950 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, 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. NOTE 7 FINANCIAL INSTRUMENTS The Company had $175 million of fixed-rate long-term debt outstanding at September 30, 2007, which had an estimated fair value of $182 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 bears 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. 89 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, 2007 September 30, 2006 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $11,329 $19,413 $117,646 $122,490 $ — $(115) $128,975 $141,788 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, 2007, 2006, and 2005, marketable equity available-for-sale securities with a fair value at the date of sale of $73.4 million, $28.2 million, and $46.7 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $65.5 million, $19.8 million, and $27.0 million, respectively. The investments in the limited partnerships carried at cost were approximately $12.4 million at September 30, 2007 and 2006. The estimated fair value of the limited partnerships was $22.3 million and $14.5 million at September 30, 2007 and 2006, respectively. The estimated fair value exceeded the cost of investments at September 30, 2007 and 2006 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 $7.8 million and $5.9 million at September 30, 2007 and 2006, 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 were classified as available-for-sale. All of the auction rate securities were U.S. state and local municipal securities due within one year and reported on the balance sheet at fair value. The interest or dividend rates on the Company’s auction rate securities were generally reset every 7 to 49 days through an auction process, thus limiting the Company’s exposure to interest rate risk. Interest and dividends were paid on these securities at the end of each reset period and included in interest and dividend income on the Company’s Consolidated Statements of Income. The Company sold all of the auction rate securities, $48.3 million, during the year ended September 30, 2007, with no realized gains or losses. There were no unrealized gains or losses for 2007 or 2006. The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2007 and 2006. 90 NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of other comprehensive income for the years ended September 30, 2007, 2006 and 2005 were as follows (in thousands): Years Ended September 30, 2007 2006 2005 Unrealized appreciation on securities net of tax of $23,076, $18,331 and $9,343 $ 37,654 $ 29,909 $ 15,245 Reclassification of realized gains in net income net of tax of $24,874, $7,548 and $328 (40,584) (12,318) (537) Minimum pension liability adjustments net of tax of $5,621, $2,765 and ($2,094) 9,170 $ 6,240 4,510 $ 22,101 (3,416) $ 11,292 The components of accumulated other comprehensive income (loss) at September 30, 2007 and 2006, net of applicable tax effects, were as follows (in thousands): September 30, Unrealized appreciation on securities Minimum pension liability Unrecognized actuarial gain and prior service cost NOTE 9 EMPLOYEE BENEFIT PLANS 2007 $72,941 — 2,944 $75,885 2006 $75,871 (6,226) — $69,645 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 was frozen. On September 30, 2007, the Company adopted the provisions of SFAS No. 158 ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans’’ (‘‘SFAS 158’’). SFAS No. 158 is an amendment of SFAS Nos. 87, 88, 106, and 132(R) and is intended to improve financial reporting of pension and postretirement benefit plans. This statement requires employers to a) recognize the funded status of a benefit plan, determined as the difference between the fair value of plan assets and the benefit obligation, as an asset or liability in the statement of financial position, b) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, c) measure the defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end, which the Company has used historically, and d) include additional disclosures in the notes to the financial statements about effects on net periodic benefit cost that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations. 91 The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of assets over the two-year period ended September 30, 2007 and a statement of the funded status as of September 30, 2007 and 2006 (in thousands): Accumulated Benefit Obligation (‘‘ABO’’) Changes in Projected Benefit Obligations (‘‘PBO’’) Projected benefit obligation at beginning of year Service cost Interest cost Actuarial gain Benefits paid Projected benefit obligation at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return 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 *Not applicable due to adoption of new accounting standard September 30, Amounts Recognized in the Consolidated Balance Sheets (in thousands): Current pension liability Noncurrent pension liability Accumulated other comprehensive income – minimum pension liability (pre-tax) Net amount recognized The amounts recognized in accumulated other comprehensive income at September 30, 2007, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial gain Prior service cost Total 2006 $ 87,669 $ 90,217 4,713 4,841 (5,903) (6,199) $ 87,669 $ 62,955 5,575 4,421 (6,199) $ 66,752 $(20,917) 10,028 1 (10,042) $(20,930) 2006 $ — (20,930) 10,042 $(10,888) 2007 $78,247 $87,669 — 4,865 (9,980) (4,307) $78,247 $66,752 9,782 2,650 (4,307) $74,877 $ (3,370) * * — $ (3,370) 2007 $ (35) (3,335) — $(3,370) $(4,749) 1 $(4,748) The amount recognized in accumulated other comprehensive income and not yet reflected in periodic benefit cost expected to be amortized in next year’s periodic benefit cost is a net actuarial gain of $12,953. 92 The weighted average assumptions used for the pension calculations were as follows: Years Ended September 30, Discount rate for net periodic benefit costs Discount rate for year-end obligations Expected return on plan assets Rate of compensation increase 2007 5.75% 6.25% 8.00% —% 2006 5.75% 5.75% 8.00% 5.00% 2005 5.50% 5.75% 8.00% 5.00% The Company does not anticipate that funding the Pension Plan in fiscal 2008 will be required. However, the Company can choose to make discretionary contributions to fund distributions in lieu of liquidating pension assets. During 2007, the Company elected to fund $2.7 million. The Company estimates contributing at least $3.0 million in fiscal 2008. Subsequent to year end, the Company has contributed $1.5 million to the Pension Plan. Components of the net periodic benefit cost (benefit) were as follows (in thousands): Years Ended September 30, Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Net pension (income) expense 2007 $ — 4,865 (5,123) — 139 2006 $ 4,713 4,841 (4,936) (1) 876 $ (119) $ 5,493 2005 $ 3,480 4,617 (4,378) — 987 $ 4,706 The Pension Plan was frozen and benefit accruals were discontinued effective September 30, 2006, thus reducing the service cost of the Plan. 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 (in thousands). 2008 $3,080 2009 $3,303 2010 $3,471 2011 $3,573 2012 $4,062 2013-2017 $23,515 Total $41,004 Years Ended September 30, Included in the Pension Plan is an unfunded supplemental executive retirement plan. 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. 93 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 2008 and the asset allocation for the domestic Pension Plan at the end of fiscal 2007 and 2006, 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, 2008 56% 14 25 5 100% 2007 61% 18 20 1 100% 2006 60% 17 22 1 100% 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 $10.9 million, $8.4 million, and $6.1 million in 2007, 2006, and 2005, respectively. FOREIGN PLAN The Company maintains an unfunded pension plan in one of the international subsidiaries. Pension expense was approximately $0.3 million, $0.4 million and $0.3 million in 2007, 2006 and 2005, respectively. The pension liability at September 30, 2007 and 2006 was $4.1 million and $3.6 million, respectively. NOTE 10 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in the Company’s reserve for bad debt for 2007, 2006 and 2005: September 30, Reserve for bad debt: Balance at October 1, Provision for bad debt Write-off of bad debt Balance at September 30, 2007 $2,007 1,030 (80) $2,957 2006 (in thousands) $1,791 250 (34) $2,007 2005 $1,265 530 (4) $1,791 94 Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following: September 30, Accounts receivable, net of reserve: Trade receivables Insurance receivable Investment sales receivables Prepaid expenses and other: Prepaid value added tax Restricted cash Prepaid insurance Deferred mobilization Other Accrued liabilities: Taxes payable – operations Accrued income taxes Worker’s compensation liabilities Payroll and employee benefits Accrued operating costs Other 2007 2006 (in thousands) $337,829 $283,386 1,990 — — 6,093 $339,819 $289,479 $ 4,914 $ 2,597 6,203 4,685 6,202 6,870 2,273 2,432 2,907 5,910 $ 28,874 $ 16,119 $ 31,610 $ 21,316 10,033 2,406 36,010 5,185 16,812 24,991 2,371 30,124 7,200 11,075 $102,056 $ 97,077 NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2007 Cash payments: Interest paid, net of amounts capitalized Income taxes paid $ 9,713 $181,591 2006 (in thousands) $ 6,644 $109,857 2005 $12,707 $29,715 Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2007, 2006 and 2005, does not include additions which have been incurred but not paid for as of the end of the 95 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 2007 $825,448 95,720 Additions incurred but not paid for as of the end of the year (26,954) Capital expenditures per Consolidated Statements of Cash 2006 (in thousands) $614,274 10,351 (95,720) 2005 $95,007 2,149 (10,351) Flows $894,214 $528,905 $86,805 NOTE 12 RISK FACTORS CONCENTRATION OF CREDIT Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments, 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 maintains certain other insurance coverage with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce the Company’s exposure to catastrophic events. 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. Insurance coverage for ‘‘named storms’’ in the Gulf of Mexico has been limited for the past two years. The Company purchased an aggregate limit of $75 million of wind storm coverage and elected to self-insure 96 20 percent of that limit through White Eagle. Additionally, the wind storm coverage has a $2.5 million deductible. Additionally, the Company obtained rig property insurance for 80 percent of the aggregate estimated replacement cost of its rigs in excess of a $1 million deductible. The Company self-insured the remaining 20 percent of such rig value as well as the deductible. The Company also utilized White Eagle to finance self-insured losses within the $1 million per occurrence deductible under worker’s 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. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S. based parent. These dividends reduced the Company’s exposure to currency devaluation in Venezuela. On June 7, 2007, the Company began the process to make 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 $8.3 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, 2007, 2006 and 2005. As a result of the 12 percent devaluation of the bolivar during fiscal 97 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. At September 30, 2007, the Company had a $25.6 million cash balance denominated in bolivares exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2008 activity levels are similar to fiscal 2007 and if a 10 percent to 20 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $3.5 million to $6.4 million. The Company has an agreement with the Venezuelan state petroleum company whereby a portion of the Company’s dollar-based invoices are paid 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, 2007, the Company had a net receivable from PDVSA of $49.7 million of which $12.0 million was 90 days old or older. At November 1, 2007, such receivable balance had increased to approximately $50.3 million, of which approximately $14.4 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. The Ecuadorian government continues to negotiate with the Company’s customers to resolve contract disputes created by a recent government decree. The decree modified the original contracts for splitting profits on oil production. If this continues without resolution, the Company anticipates that up to seven rigs could be idle in Ecuador in the second quarter of fiscal 2008. Should this situation occur, the Company, at this time, is unable to predict the length of time that the rigs would remain idle. NOTE 13 ASSETS HELD FOR SALE In August 2006, the Company signed an option agreement to sell two offshore rigs. The net book value of the two rigs at September 30, 2006 was approximately $4.2 million and was classified as ‘‘Assets held for sale’’ in the Company’s September 30, 2006 Consolidated Balance Sheet. The purchase option was exercised in the second quarter of fiscal 2007 and the Company recorded a gain which is included in ‘‘Income from asset sales’’ in the Company’s Consolidated Statements of Income for the year ended September 30, 2007. 98 NOTE 14 COMMITMENTS AND CONTINGENCIES COMMITMENTS Since March 2005, the Company has entered into separate drilling contracts with 19 exploration and production customers to build and operate a total of 77 new FlexRigs. Subsequent to September 30, 2007, the Company announced that an agreement had been reached with an exploration and production company to operate an additional six new FlexRigs, bringing the total of the new rigs to 83. The construction of the 83 rigs is estimated to cost $1.3 billion. Approximately $0.7 billion was incurred in fiscal 2007 and approximately $0.4 billion was incurred in fiscal 2006. The construction began in the third quarter of fiscal 2005 and is estimated to continue through the third quarter of fiscal 2008. During construction, rig construction cost is 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, 2007, the Company had commitments outstanding of approximately $82.7 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 also conducts certain operations in leased premises and leases telecommunication equipment. Future minimum lease payments required under noncancelable operating leases as of September 30, 2007 are as follows (in thousands): Fiscal Year 2008 2009 2010 2011 Thereafter Total Amount $ 3,982 2,958 1,214 — — $ 8,154 Total rent expense was $3.7 million, $3.1 million and $2.3 million for 2007, 2006 and 2005, respectively. CONTINGENCIES In August 2007, the Company experienced a fire on U.S. Land Rig 178, a 1,500 horsepower FlexRig2, when the well it was drilling had a blowout. There were no significant personal injuries although the drilling rig was lost. The rig was insured at a value that approximated replacement cost. At September 30, 2007, the net book value of the rig was removed from property, plant and equipment and a receivable from insurance was recorded, net of a $1.0 million insurance deductible expensed. Subsequent to September 30, 2007, gross insurance proceeds of approximately $8.5 million were received and a gain of approximately $4.8 million was 99 recorded. The Company anticipates settling the insurance claim before the end of the second quarter of fiscal 2008 and expects to receive additional insurance proceeds of less than $0.5 million. 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. Capital costs incurred in conjunction with rebuilding the rig were capitalized in fiscal 2007 and are being 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 approximated the net book value of equipment lost in the hurricane and, therefore, no gain was recognized in fiscal 2006. In fiscal 2007, insurance proceeds of approximately $16.3 million were received and the Company recorded a gain from involuntary conversion of long-lived assets of approximately $16.7 million. The proceeds are in the Consolidated Statements of Cash Flows under investing activities. Additional claims have been submitted and future proceeds will be recorded as gain from involuntary conversion of long-lived assets when received. The Company expects to settle this claim in fiscal 2008 and estimates additional proceeds to range from $5 million to $10 million. Various legal actions, the majority of which arise in the ordinary course of business, are pending. The Company maintains insurance against certain business risks subject to certain deductibles. None of these legal actions are expected to have a material adverse effect on the Company’s financial condition, cash flows or results of operations. The Company is contingently liable to sureties in respect of bonds issued by the sureties in connection with certain commitments entered into by the Company in the normal course of business. The Company has agreed to indemnify the sureties for any payments made by them in respect of such bonds. 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, Offshore, and International Land. The contract drilling operations consist mainly of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company’s primary international areas of operation include Venezuela, Colombia, Ecuador and other South American countries. The International Land 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. 100 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. In the fourth quarter of fiscal 2007, the Company began mobilizing an offshore rig from the U.S. to an international location. Because an offshore rig requires different technology and marketing strategies, the chief operating decision-maker’s evaluation of performance and resource allocation for this rig is more appropriately aligned with the Offshore segment. Therefore the Company will continue to include the operations of this rig in the Offshore operating segment. In conjunction with this, the Company has determined that a management contract for a customer-owned platform rig located offshore in North Africa is more appropriately aligned with the Offshore segment for purposes of evaluating performance and resource allocation. Therefore, this management contract has been reclassed from the International segment to the Offshore segment in fiscal 2007. In conjuction with this, the International segment was renamed to International Land. Financial information for reportable segments for fiscal 2006 and 2005 has been restated to reflect this change. 101 Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2007, 2006, and 2005 is shown in the following table: (in thousands) 2007 Contract Drilling U.S. Land Offshore International Land Real Estate Other Eliminations Total 2006 Contract Drilling U.S. Land Offshore International Land Real Estate Other Eliminations Total 2005 Contract Drilling U.S. Land Offshore International Land Real Estate Other Eliminations External Sales Inter- Segment Total Sales Segment Operating Income Depreciation Total Assets Additions to Long-Lived Assets $1,174,956 $ — $1,174,956 $467,000 $106,107 $2,073,015 $762,501 123,148 320,283 1,618,387 11,271 1,629,658 — — — — 828 828 — — (828) 123,148 22,081 10,687 124,014 25,418 320,283 1,618,387 12,099 105,179 594,260 5,007 23,782 314,625 22,726 140,576 2,511,654 810,645 2,456 30,351 1,510 1,630,486 599,267 143,032 2,542,005 812,155 — (828) — — 3,010 — 343,364 13,293 — — $1,629,658 $ — $1,629,658 $599,267 $146,042 $2,885,369 $825,448 $ 829,062 $ — $ 829,062 $351,255 $ 66,127 $1,356,817 $560,664 154,543 230,829 1,214,434 10,379 1,224,813 — — — — 783 783 — — (783) 154,543 31,865 11,401 110,961 18,756 230,829 52,318 1,214,434 435,438 11,162 4,411 19,471 96,999 2,444 310,836 31,245 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 — $1,224,813 $ — $1,224,813 $439,849 $101,583 $2,134,712 $614,274 $ 527,637 $ — $ 527,637 $164,657 $ 60,222 $ 809,403 $ 78,499 106,296 156,105 790,038 10,688 800,726 — — — — 761 761 — — (761) 106,296 22,013 10,639 95,913 1,059 156,105 790,038 11,449 14,668 201,338 4,714 20,070 90,931 2,352 238,282 1,143,598 32,203 801,487 206,052 93,283 1,175,801 — (761) — — 2,991 — 487,549 — 12,437 91,995 1,517 93,512 1,495 — Total $ 800,726 $ — $ 800,726 $206,052 $ 96,274 $1,663,350 $ 95,007 102 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 Gain from involuntary conversion of long-lived assets 2007 2006 2005 $ 599,267 $ 439,849 $206,052 41,697 16,661 7,492 13,550 — — Corporate general and administrative costs and corporate depreciation (25,306) (30,055) (26,846) Operating income Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Total unallocated amounts 632,319 417,286 192,756 4,234 (10,126) 65,458 (1,532) 58,034 9,834 (6,644) 19,866 639 5,809 (12,642) 26,969 (235) 23,695 19,901 Income before income taxes and equity in income of affiliate $ 690,353 $ 440,981 $212,657 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, 2007 2006 2005 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $1,292,636 $ 972,021 $623,246 127,278 93,903 26,849 88,992 84,594 88,709 17,748 61,741 66,824 60,946 12,792 36,918 $1,629,658 $1,224,813 $800,726 $1,951,907 $1,284,235 $810,489 83,804 45,120 10,061 61,724 83,160 42,859 9,793 63,087 84,461 44,250 9,213 33,552 $2,152,616 $1,483,134 $981,965 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 10.8 percent, 11.2 percent, and 11.1 percent of the total operating revenues during the years ended September 30, 2007, 2006, and 2005, respectively. The receivable from this customer was approximately $34.4 million and $29.1 million at September 30, 2007 and 2006, respectively. 103 NOTE 16 SUBSEQUENT EVENTS On November 15, 2007, the Company announced a three-year term contract had been reached with an exploration and production company to operate six new FlexRigs. With these contracts, the Company has now committed to build 83 new FlexRigs, of which 70 had been completed as of September 30, 2007. NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2007 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 $386,399 $372,536 $421,274 $449,449 146,654 110,786 1.07 1.06 164,284 106,861 1.04 1.02 154,672 115,204 1.11 1.09 166,709 116,410 1.13 1.10 2006 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 $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 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. In the first quarter of fiscal 2007, net income includes an after-tax gain on sale of available-for-sale securities of $16.2 million, $0.15 per share on a diluted basis. In the second quarter of fiscal 2007, net income includes an after-tax gain from the sale of assets of $20.5 million, $0.20 per share on a diluted basis and an after-tax gain from involuntary conversion of long-lived assets of $3.3 million, $0.03 per share on a diluted basis. In the third quarter of fiscal 2007, net income includes an after-tax gain on sale of available-for-sale securities of $15.5 million, $0.15 per share on a diluted basis, an after-tax gain from the sale of assets of $3.9 million, $0.03 per share on a diluted basis, and an after-tax gain from involuntary conversion of long-lived assets of $3.7 million, $0.03 per share on a diluted basis. In the fourth quarter of fiscal 2007, net income includes an after-tax gain on sale of available-for-sale securities of $8.4 million, $0.08 per share on a diluted basis, an after-tax gain from the sale of assets of 104 $1.9 million, $0.01 per share on a diluted basis, and an after-tax gain from involuntary conversion of long-lived assets of $3.6 million, $0.04 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. 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. Performance Graph The following performance graph reflects the yearly percentage change in the Company’s cumulative total stockholder return on common stock as compared with the cumulative total return of the S&P 500 Index and the S&P 500 Oil & Gas Drilling Index. All cumulative returns assume reinvestment of dividends and are calculated on a fiscal year basis ending on September 30 of each year. CUMULATIVE TOTAL RETURN ON COMMON STOCK $400 $350 $300 $250 $200 $150 $100 $50 $0 Sep02 Sep03 Sep04 Sep05 Sep06 Sep07 HELMERICH & PAYNE S&P 500 INDEX S&P 500 OIL & GAS DRILLING INDEX 20NOV200717095391 105 Directors Officers 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 Randy A. Foutch*(***) Chairman, President and Chief Executive Officer Laredo Petroleum, Inc. Tulsa, Oklahoma Paula Marshall**(***) Chief Executive Officer The Bama Companies, Inc. Tulsa, Oklahoma Edward B. Rust, Jr.*(***) Chairman, President 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 106 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, U.S. and International Operations of Helmerich & Payne International Drilling Co. M. Alan Orr Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. Stockholders’ Meeting The annual meeting of stockholders will be held on March 5, 2008. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 25, 2008. 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 November 21, 2007, there were 703 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. Our Transfer Agent is responsible for our shareholder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with The Transfer Agent at the following address: Computershare Trust Company, N.A. Investor Services P.O. Box 43078 Providence, RI 02940-3078 Telephone: (800) 884-4225 (781) 575-4706 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 Guidelines and Code of Business Conduct and Ethics; the Code of Ethics for Principal Executive Officer and Senior Financial Officers; the Related Person Transaction Policy; certain Audit Committee Practices and a description of the means by which employees and other interested persons may communicate certain concerns to the Company’s Board of Directors, including the communication of such concerns confidentially and anonymously via the Company’s ethics hotline at 1-800-205-4913. Quarterly reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request. Annual CEO Certification The annual CEO Certification required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual was provided to the New York Stock Exchange on or about March 29, 2007. 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 5DEC200715150958 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 ANNUAL REPORT FOR 2007 

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