HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2009 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, Mexico, Trinidad and Africa. Holdings also include commercial real estate properties in the Tulsa, Oklahoma, area, and an energy-weighted portfolio of securities valued at approximately $360 million as of September 30, 2009. F I N A N C I A L H I G H L I G H T S 10DEC200911261602 Years Ended September 30, 2009 2008 2007 Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets (in thousands, except per share amounts) $1,894,038 353,545 3.32 0.2000 880,753 4,161,024 $2,036,543 461,738 4.34 .1850 705,635 3,588,045 $1,629,658 449,261 4.27 .1800 894,214 2,885,369 To the Co-owners of Helmerich & Payne, Inc.: A year ago at this time, we understood that 2009 would be a challenging year for the drilling business, but we were still somewhat dismayed by the rapidity and extent of a decline that rivaled what the industry experienced in the early 1980s. In our largest segment, U.S. Land, the utilization rate fell from an average of 97 percent in October to a low of about 50 percent in June, which was significantly higher than that of our peer group. Customers seeing both the collapse in commodity prices and the implosion of the credit markets took drastic measures to conserve cash flow and protect their balance sheets by cutting drilling programs to the bone. Consequently, the Company received termination notices on term contracts representing 37 U.S. Land new build rigs, each of which had begun work prior to fiscal 2008. The option for the early termination fee was built into each of our term contracts to provide our customers with the flexibility to change their plans in mid-stream while at the same time protecting the Company for the significant financial commitments it made to build new high efficiency rigs. Although our capital risk was mitigated, we would have much preferred to continue the contracts and keep our people intact and fully engaged. While we are encouraged by the improvement in the energy markets since the low point early last year, we remain cautious about current supply and demand dynamics and what they mean for natural gas pricing during 2010. Prospects for any sustained price improvement will depend on natural gas demand in 2010. Industrial demand was hammered this past year and the size of the rebound will be tied to achieving real economic recovery. Weather related demand, aided by a winter with above average heating days, could also play an important role. Longer term opportunities for improved natural gas demand are plentiful, including inroads into the transportation fuel market. Of course, on the supply side of the equation, caution abounds, especially in the short-term. In addition to the well known gas shale potential, all-time high gas inventory levels are currently buttressed by a sizeable backlog of uncompleted wells. Some estimate there are approximately 1,500 of these deferred wells in the U.S. Future LNG imports are an ongoing source of added supply potential with worldwide capacity having jumped by a third in the last two years. It is uncertain how much of this new capacity will land in the U.S. While these concerns set up a possible ‘‘2nd bottom,’’ we believe the more likely outcome is that they act to somewhat flatten the curve and push it to the right. In many respects, avoiding some of the typical volatility even on the upside would be a good thing. Arguably, the worst thing for the industry would be another price spike. One silver lining of this past year was that lower utilization created opportunities for us to appeal to new customers, who may not have tried a FlexRig before for lack of availability. Six FlexRigs began working in Mexico under a Schlumberger Integrated Project Management contract and we also moved four rigs to the Marcellus in Pennsylvania, which is fast becoming a key natural gas basin in the lower 48. All told, we have initiated work with 25 first time FlexRig users and all of them had cheaper alternatives in terms of dayrates. Winning new customers speaks to a larger point of gaining market share in good times and bad. Not long ago, we were number five in terms of market share in U.S. Land Drilling. This calendar year, while we still don’t have the largest fleet, we achieved the highest amount of drilled footage through October in the lower 48 land market. As we’ve gained market share, we have also maintained premium margins to our peer group, becoming the U.S. land drilling industry’s most profitable contractor during our fiscal year. As the industry slowly recovers, we have no illusions about the environment we’re faced with. Keeping our focus on the customer’s need for efficiency and safety in the field will continue to drive our long-term success. Of course that success is earned every day, 24-7. It requires hard work, a focus on safety, and is often conducted under challenging conditions. As the Company begins its 90th year as the industry’s oldest land contractor, I am reminded that it is the strong values of our past, combined with a drive for innovation and improved performance that secures our future. In that spirit, I feel a deep sense of gratitude toward the H&P men and women whose commitment and loyalty continue to make that possible. Sincerely, 11DEC200619131880 Hans Helmerich President November 25, 2009 Financial & Operating Review Years Ended September 30, 2009 2008 2007 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 Net Income from Continuing Operations Net Income Diluted Earnings Per Common Share: Net 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 4 $1,894,038 1,011,558 236,437 59,413 583,532 4,965 — 13,490 353,545 353,545 $2,036,543 1,086,666 210,766 57,059 692,816 5,038 21,994 18,689 461,738 461,738 $1,629,658 862,254 146,042 47,401 632,319 4,234 65,458 10,126 449,261 449,261 3.32 3.32 4.34 4.34 4.27 4.27 $ 141,486 221,026 356,404 3,265,907 4,161,024 420,000 2,683,009 880,753 $ 121,513 381,690 199,266 2,682,251 3,588,045 475,000 2,265,474 705,635 $ 89,215 272,352 223,360 2,152,616 2,885,369 445,000 1,815,516 894,214 163 11 27 9 44 254 76 29 39 68 89 68 146 12 27 9 30 224 100 83 80 96 75 82 118 12 27 9 27 193 100 93 87 97 65 90 2006 2005 2004 2003 2002 2001 2000 1999 $1,224,813 661,563 101,583 51,873 417,286 9,834 19,866 6,644 293,858 293,858 $ 800,726 484,231 96,274 41,015 192,756 5,809 26,969 12,642 127,606 127,606 $ 589,056 417,716 145,941 37,661 (6,885) 1,965 25,418 12,695 4,359 4,359 $ 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 2.77 2.77 1.23 1.23 .04 .04 .18 .18 .53 .63 .79 1.42 .36 .82 .32 .43 $ 33,853 164,143 218,309 1,483,134 2,134,712 175,000 1,381,892 528,905 $ 288,752 410,316 178,452 981,965 1,663,350 200,000 1,079,238 86,805 $ 65,296 185,427 161,532 998,674 1,406,844 200,000 914,110 90,212 $ 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 73 12 28 9 27 149 100 100 95 99 69 90 50 12 29 11 26 128 100 99 82 94 53 77 48 11 28 11 32 130 99 91 67 87 48 54 43 11 29 12 32 127 97 89 58 81 51 39 5 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 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 0 9 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2009 OR (cid:3) 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 Each 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:2) No (cid:3) 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:3) No (cid:2) 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:2) No (cid:3) Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes (cid:2) No (cid:3) 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:3) Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of ‘‘large accelerated filer,’’ ‘‘accelerated filer’’ and ‘‘smaller reporting company’’ in Rule 12b-2 of the Exchange Act. Large accelerated filer (cid:2) Accelerated filer (cid:3) Smaller reporting company (cid:3) Non-accelerated filer (cid:3) (Do not check if a smaller reporting company) Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:3) No (cid:2) At March 31, 2009 the aggregate market value of the voting stock held by non-affiliates was $2,319,845,079 Number of shares of common stock outstanding at November 19, 2009: 105,553,595 DOCUMENTS INCORPORATED BY REFERENCE Certain portions of the following documents have been incorporated by reference into this Form 10-K as indicated: 10-K Parts Documents (1) Annual Report to Stockholders for the fiscal year ended September 30, 2009 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 3, 2010 Parts I and II Part III DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS THIS REPORT INCLUDES ‘‘FORWARD-LOOKING STATEMENTS’’ WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT’S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD- LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD- LOOKING TERMINOLOGY SUCH AS ‘‘MAY’’, ‘‘WILL’’, ‘‘EXPECT’’, ‘‘INTEND’’, ‘‘ESTIMATE’’, ‘‘ANTICIPATE’’, ‘‘BELIEVE’’, OR ‘‘CONTINUE’’ OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT’S EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION ‘‘RISK FACTORS’’ BEGINNING ON PAGE 6, AS WELL AS IN MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 6 THROUGH 41 OF THE COMPANY’S ANNUAL REPORT (EXHIBIT 13 TO THIS FORM 10-K). 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, 2009 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 Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion and 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 6 11 11 17 17 18 19 19 19 20 20 20 20 23 24 24 24 24 24 25 29 ii HELMERICH & PAYNE, INC. AND SUBSIDIARIES Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 2009 Item 1. BUSINESS PART I Helmerich & Payne, Inc. (hereafter referred to as the ‘‘Company’’, ‘‘we’’, ‘‘us’’ or ‘‘our’’), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. We are primarily engaged in contract drilling of oil and gas wells for others and this business accounts for almost all of our operating revenues. Our contract drilling business is composed of three reportable business segments: U.S. land drilling, offshore drilling and international land drilling. Our U.S. land drilling is conducted primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Pennsylvania, Utah, Arkansas, New Mexico, and North Dakota. Offshore drilling operations are conducted in the Gulf of Mexico, and offshore of California, Trinidad and Equatorial Guinea. Our international land segment operated in six international locations during fiscal 2009: Venezuela, Ecuador, Colombia, Argentina, Mexico and Tunisia. We are also engaged in the ownership, development and operation of commercial real estate and research and development of rotary steerable technology. Each of the businesses operates independently of the others through wholly-owned subsidiaries. This operating decentralization is balanced by a centralized finance division, which handles all accounting, information technology, budgeting, insurance, cash management and related activities. Our real estate investments located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately 441,000 leasable square feet, multi-tenant industrial warehouse properties containing approximately 990,000 leasable square feet and approximately 210 acres of undeveloped real estate. Our subsidiary, TerraVici Drilling Solutions, Inc. (‘‘TerraVici’’), is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with the FlexRig. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer. CONTRACT DRILLING General We believe that we are one of the major land and offshore drilling contractors in the western hemisphere. Operating principally in North and South America, we specialize 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, we draw our customers primarily from the major oil companies and the larger independent oil companies. In South America, our current customers include the Venezuelan state petroleum company and major international oil companies. In fiscal 2009, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers. Devon Energy Production Co. LP, Occidental Oil and Gas Corporation and BP plc (respectively, ‘‘Devon’’, ‘‘Oxy’’ and ‘‘BP’’), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Devon in U.S. land operations, and for Oxy and BP on a world-wide basis. Revenues from drilling services performed for Devon, Oxy and BP in fiscal 2009 accounted for approximately 12 percent, 10 percent and 9 percent, respectively, of our consolidated operating revenues for the same period. Rigs, Equipment and Facilities We provide drilling rigs, equipment, personnel and camps on a contract basis. These services are provided so that our 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 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, we operate 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. In 1998, we put to work a new generation of six highly mobile/depth flexible land drilling rigs (individually the ‘‘FlexRig(cid:2)’’). The FlexRig has been able to significantly reduce average rig move and drilling 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, we built and completed 12 new FlexRig2 rigs. In 2001, we announced that we 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, we constructed seven more FlexRig3s which were completed by March of 2004. From March 2005 through November 2008, we announced commitments with exploration and production companies to build a cumulative total of 140 new FlexRigs under fixed term contracts to perform drilling services on a daywork basis. Of the 140 FlexRigs, 57 are FlexRig3s and 83 are FlexRig4s (described below). We completed 133 of the 140 rigs through fiscal 2009 and have seven remaining new FlexRigs to complete by the end of the third quarter of fiscal 2010. The total estimated construction cost of all 140 rigs, including tubular and other ancillary equipment, is currently $2.2 billion. While the new FlexRig4s are similar to our 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 permits the installation of 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 our competitive position within the drilling industry. As a result of the importance of technology to our business, we expect to continue to develop technology internally. We assemble new FlexRigs at our gulf coast facility near Houston, Texas. We also have a 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma. Drilling Contracts Our 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 2009, all drilling services were performed on a ‘‘daywork’’ contract basis, under which we charge 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. We have previously performed contracts on a combination ‘‘footage’’ and ‘‘daywork’’ basis, under which we 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, we have previously accepted ‘‘turnkey’’ contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole 2 which are not normally done on a ‘‘footage’’ basis. ‘‘Turnkey’’ contracts entail varying degrees of risk greater than the usual ‘‘footage’’ contract. We have not accepted any ‘‘footage’’ or ‘‘turnkey’’ contracts for at least the last ten years. We believe that under current market conditions, ‘‘footage’’ and ‘‘turnkey’’ contract rates do not adequately compensate contractors for the added risks. The duration of our 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 us 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, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. As of September 30, 2009, we had 107 rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for twelve-month to seven-year periods, some fixed-term and well-to-well contracts are expected to be extended 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 us and the customer. In most instances contracts provide for additional payments for mobilization and demobilization. Backlog Our contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2009 and 2008 was $2,528 million and $3,374 million, respectively. The decrease in our backlog from 2008 to 2009 is primarily due to expiration and early termination of long-term contracts. Approximately 63.0 percent of the total September 30, 2009 backlog is not reasonably expected to be filled in fiscal 2010. Term contracts customarily provide for termination at the election of the customer with an ‘‘early termination payment’’ to be paid to us 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, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid. In addition, a portion of the backlog represents term contracts for new rigs that will be constructed in the future. We obtain 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 Item 1A. Risk Factors. The following table sets forth the total backlog by reportable segment as of September 30, 2009 and 2008, and the percentage of the September 30, 2009 backlog not reasonably expected to be filled in fiscal 2010: Reportable Segment U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Total Backlog Revenue 9/30/2009 9/30/2008 (in millions) $2,016 169 343 $2,528 $2,876 199 299 $3,374 Percentage Not Reasonably Expected to be Filled in Fiscal 2010 61.1% 74.6% 68.5% 3 U.S. LAND DRILLING At the end of September 2009, 2008 and 2007, we had 201, 185 and 157, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2009 increased by a net of 16 rigs from the end of fiscal 2008. The increase is due to 22 new FlexRigs having been completed and placed into service, 7 rigs completed and ready for service, 12 transferred to international operations and 1 rig removed as held for sale. Our U.S. land operations contributed approximately 76 percent ($1,441.2 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 76 percent ($1,542.0 million) of consolidated operating revenues during fiscal 2008 and approximately 72 percent ($1,174.9 million) of consolidated operating revenues during fiscal 2007. Rig utilization in fiscal 2009 was approximately 68 percent, down from approximately 96 percent in fiscal 2008 and 97 percent in 2007. Our fleet of FlexRigs maintained an average utilization of approximately 76 percent during fiscal 2009 while our conventional and highly mobile rigs had an average utilization rate of approximately 36 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2009, 111 land rigs were working out of 201 available rigs. OFFSHORE DRILLING Our offshore operations contributed approximately 11 percent ($204.7 million) in fiscal 2009 of our consolidated operating revenue compared to 8 percent in both fiscal years 2008 and 2007 ($154.5 million in fiscal 2008 and $123.1 million in fiscal 2007). Rig utilization in fiscal 2009 was approximately 89 percent, up from approximately 75 percent in fiscal 2008 and 65 percent in fiscal 2007. At the end of fiscal 2009, we had seven of our 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 terminated in early fiscal 2008 but we have continued under 30-day extensions. Currently, we are negotiating a new contract in Equatorial Guinea and expect returning to a full dayrate in fiscal 2010. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 36 percent of offshore revenues during fiscal 2009. INTERNATIONAL LAND DRILLING General Our international land operations contributed approximately 13 percent ($237.4 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 16 percent ($328.2 million) of consolidated operating revenues during fiscal 2008 and 20 percent ($320.3 million) in fiscal 2007. Rig utilization in fiscal 2009 was 68 percent, 82 percent in fiscal 2008 and 90 percent in fiscal 2007. Venezuela We worked exclusively for the Venezuelan state petroleum company, PDVSA and a PDVSA-owned affiliate, during fiscal 2009 and revenues from this work accounted for approximately 21 percent of international operating revenues. Revenues recognized from Venezuelan drilling operations contributed approximately 3 percent ($50.3 million) of our consolidated operating revenues in fiscal 2009 compared to 8 percent in both fiscal years 2008 and 2007 ($167.2 million in fiscal 2008 and $127.3 million in fiscal 2007). We determined that as of the beginning of the second quarter of fiscal 2009 and forward, PDVSA no longer met the revenue recognition criteria as collectability became uncertain. As a result of this change, revenue of $57.9 million was not recorded in fiscal 2009. As a result of the uncertainty regarding the timing of collection of accounts receivables in U.S. dollars from PDVSA, during the second fiscal quarter of 2009, we decided to discontinue work as contracts expire. All of our eleven rigs were active in Venezuela at the end of 2008. At the end of fiscal 2009, one rig remained active and has since become idle. As a result, rig utilization in Venezuela decreased to approximately 64 percent in fiscal 2009 compared to approximately 97 percent during fiscal 2008 and approximately 92 percent in fiscal 2007. We will continue to pursue future drilling opportunities in Venezuela, but we do not expect to commit to new contracts until additional progress is made on pending accounts receivable and converting local currency to U.S. dollars. For additional information, see Item 1A. Risk Factors. 4 Colombia At the end of fiscal 2009, we had six rigs in Colombia. Our utilization rate was approximately 88 percent during fiscal 2009, approximately 87 percent during fiscal 2008 and approximately 100 percent during fiscal 2007. Revenues generated by Colombian drilling operations contributed approximately 4 percent ($77.3 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 2 percent in both fiscal years 2008 and 2007 ($42.4 million in fiscal 2008 and $26.8 million in fiscal 2007). Revenues from drilling services performed for our largest customer in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 20 percent of international operating revenues during fiscal 2009. The Colombian drilling contracts are primarily with large international or national oil companies. Ecuador At the end of fiscal 2009, we had four rigs in Ecuador. The utilization rate in Ecuador was 100 percent in fiscal 2009, compared to 59 percent in fiscal 2008 and 89 percent in fiscal 2007. Revenues generated by Ecuadorian drilling operation contributed approximately 3 percent ($52.3 million in fiscal 2009 and $55.1 million in fiscal 2008) of our consolidated operating revenues for both fiscal years 2009 and 2008 compared to 6 percent ($93.9 million) of our consolidated operating revenues during fiscal 2007. Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 2 percent of consolidated operating revenues and approximately 17 percent of international operating revenues during fiscal 2009. The Ecuadorian drilling contracts are primarily with large international or national oil companies. Argentina At the end of fiscal 2009, we had nine rigs in Argentina. Our utilization rate was approximately 52 percent during fiscal 2009, approximately 88 percent during fiscal 2008 and approximately 100 percent during fiscal 2007. Revenues generated by Argentine drilling operations contributed approximately 2 percent of our consolidated operating revenues during fiscal 2009, 2008 and 2007 ($42.1 million, $44.4 million and $39.3 million, respectively). Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 1 percent of consolidated operating revenues and approximately 11 percent of international operating revenues during fiscal 2009. The Argentine drilling contracts are primarily with large international or national oil companies. Other Locations In addition to our operations discussed above, at the end of fiscal 2009 we had one rig in Tunisia, six rigs in Mexico, one rig en route to Africa and five rigs being used for prospective bidding purposes internationally. One new FlexRig was completed and ready for international delivery at September 30, 2009. The new rig is under contract with the location for work to be determined by the operator. 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 77 through 80 of our Annual Report (Exhibit 13 to this Form 10-K). EMPLOYEES We had 4,250 employees within the United States (13 of which were part-time employees) and 1,134 employees in international operations as of September 30, 2009. AVAILABLE INFORMATION Information relating to our internet address and information relating to our Securities and Exchange Commission (‘‘SEC’’) filings may be found on, and is incorporated by reference to, page 82 of our Annual Report (Exhibit 13 to this Form 10-K). 5 Item 1A. RISK FACTORS In addition to the risk factors discussed elsewhere in this Report, we caution that the following ‘‘Risk Factors’’ could have a material adverse effect on our business, financial condition and results of operations. A sluggish global economy may affect our business. As a result of recent volatility in oil and natural gas prices and substantial uncertainty in the capital markets due to the global economic recession and continuing sluggish global economic environment, we are unable to determine whether our customers will further reduce spending on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current reduced level of operations, fulfill their commitments and/or fund future operations and obligations. The current global economic environment may continue to impact industry fundamentals and result in continued reduced demand for drilling rigs. These conditions could have a material adverse effect on our 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, we have been successful in establishing long-term relationships with certain customers which have allowed us to secure drilling work even though we may not have been the lowest bidder for such work. We have continued to attempt to differentiate our services based upon our FlexRigs and our 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 our competitors could negatively affect our ability to differentiate our services. Our operations are subject to a number of operational risks, including weather. Our drilling operations 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. Our offshore 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, we operate 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 our platform rigs are not directly damaged by such storms, we may experience disruptions in operations due to damage to customer platforms and other related facilities in the area. We have a new-build rig assembly facility located near the Houston, Texas ship channel. Also, our 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. Fixed-term contracts may in certain instances be terminated without an early termination payment. Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an ‘‘early termination payment’’ to be paid to us 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, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, the the current global economic environment may affect the customer’s ability to pay the early termination payment. 6 Our operations present risks of loss that, if not insured or indemnified against, could adversely affect our results of operations. With the exception of ‘‘named wind storm’’ risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1.0 million per occurrence deductible, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering six offshore platform rigs for ‘‘named wind storm’’ risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers two rigs and has a $40 million limit and a $3.5 million deductible. Rig property insurance coverage expires in May 2010. No insurance is carried against loss of earnings or business interruption. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, we are generally indemnified under our drilling contracts from this risk. We have 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. We maintain certain other insurance coverages with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We retain a significant portion of our expected losses under our worker’s compensation, general liability and automobile liability programs. We record 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 adjuster estimates, historical experience or statistical methods that we believe 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. No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal 2010 or that insurance coverage will continue to be available at rates considered reasonable. No assurance can be given that our insurance and indemnification arrangements will adequately protect us against all liabilities that could result from the hazards of our drilling operations. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition and results of operations. Shortages of drilling equipment and supplies could adversely affect our operations. 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. Any such delays or shortages could have a material adverse effect on our business, financial condition and results of operations. We depend on a limited number of vendors, some of which are thinly capitalized and the loss of any of which could disrupt our operations. Certain key rig components are either purchased from or fabricated by a single or limited number of vendors, and we have 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 we are unable to procure certain of such rig components, we would be required to reduce our rig construction or other operations, which could have a material adverse effect on our business, financial condition and results of operations. If our principal fabricator, located on the Texas gulf coast, was unable or unwilling to continue fabricating rig components, then we 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 our business, financial condition and results of operations. 7 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 us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. Therefore, disruptions in rig component delivery may occur, and such disruptions and terminations could have a material adverse effect on our business, financial condition and results of operations. Oil and natural gas prices are volatile, and low prices could negatively affect our financial results in the future. Our operations can be materially affected by low oil and gas prices. We believe 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 our services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for our services could have a material adverse effect on our business, financial condition and results of operations. International uncertainties and local laws could adversely affect our business. 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 our operations or on our ability to continue operations in certain areas. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable. Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, we could experience shortages in labor and/or materials and supplies necessary to operate some or all of our Venezuelan drilling rigs, which could have a material adverse effect on our business, financial condition and 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 loss of all or a portion of our assets and business in Venezuela. Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2009, approximately 13 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2009, approximately 93 percent of the international operating revenues were from operations in South America and approximately 57 percent of South American operating revenues were from Venezuela and Colombia. Our business and results of operations may be adversely affected by foreign currency devaluation. 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 8 frequently requesting that a greater proportion of these payments be made in local currencies. Based upon current information, we believe that exposure to potential losses from currency devaluation is immaterial in Colombia, Mexico, Equatorial Guinea, Trinidad 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. We invoice in U.S. dollars and are paid in pesos equivalent to the dollar invoice. Our Argentine subsidiary remits the dollars to the parent by exchanging pesos through the Argentine Central Bank. The exchange rate between the U.S. dollar and the Argentine peso stayed within a narrow range for seven years and then devalued 27 percent during fiscal 2009, which resulted in our recording of a $2.2 million currency loss. Venezuela We are exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte (Bsf) net working capital (current assets minus current liabilities) balances, which at fiscal year end 2009 was approximately $71.4 million U.S. dollar equivalent. While we are unable to predict the potential magnitude and timing of future devaluation in Venezuela, if current activity levels continue and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, at this time we have no reason to believe the amounts owed will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than those of our other customers. 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 our business, financial condition and results of operations. Government regulations and environmental laws could adversely affect our business. Many aspects of our 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, we are 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. We believe that we are in substantial compliance with all legislation and regulations affecting our operations in the drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance has not materially affected our capital expenditures, earnings, or competitive position, although compliance measures may add to the costs of drilling operations. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on our operations cannot be predicted. Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. We have in place a $400 million senior unsecured credit facility which expires in December of 2011. We had $70 million borrowed and two letters of credit totaling $21.9 million outstanding against the facility at September 30, 2009. As of November 20, 2009, borrowings under the facility had declined to $40 million. The interest rate on the borrowings is based on a spread over LIBOR and we pay 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 our total debt to total capitalization. We also have the option to borrow at the prime rate for maturities of less than 30 days. Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amount borrowed against the credit lines. 9 Our securities portfolio may lose significant value due to a decline in equity prices and other market- related risks, thus impacting our debt ratio and financial strength. At September 30, 2009, we had a portfolio of securities with a total fair value of $360 million. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet with changes in unrealized after-tax value reflected in the equity section of our balance sheet. Any reduction in fair value would have an impact on our debt ratio and financial strength. At November 19, 2009, the fair value of the portfolio had increased to approximately $387 million. The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations. In fiscal 2009, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 31 percent of our consolidated operating revenues from our three largest customers (including their affiliates). We believe that our relationship with all of these customers is good; however, the loss of one or more of our larger customers would have a material adverse effect on our business, financial condition and results of operations. Competition for experienced technical personnel may negatively impact our operations or financial results. We utilize highly skilled personnel in operating and supporting our businesses. In times of high utilization, it can be difficult to find qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact our business, financial condition and results of operations. New technologies may cause our drilling methods and equipment to become less competitive, resulting in an adverse effect on our financial condition and results of operations. Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive. 10 Item 1B. UNRESOLVED STAFF COMMENTS We have received no written comments regarding our periodic or current reports from the staff of the Securities and Exchange Commission that were issued 180 days or more preceding the end of our 2009 fiscal year and that remain unresolved. Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning our U.S. drilling rigs as of September 30, 2009: Location FLEXRIGS TEXAS TEXAS TEXAS TEXAS OKLAHOMA MISSISSIPPI NORTH DAKOTA NORTH DAKOTA TEXAS TEXAS TEXAS LOUISIANA TEXAS OKLAHOMA TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS COLORADO TEXAS PENNSYLVANIA TEXAS TEXAS LOUISIANA TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS CALIFORNIA COLORADO CALIFORNIA NORTH DAKOTA TEXAS TEXAS TEXAS Rig Optimum Depth (Feet) Rig Type Drawworks: Horsepower 164 165 166 167 168 169 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 221 222 223 225 226 227 229 233 236 239 240 241 243 244 246 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 11 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 TEXAS TEXAS OKLAHOMA OKLAHOMA LOUISIANA TEXAS NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA TEXAS CALIFORNIA CALIFORNIA TEXAS TEXAS OKLAHOMA TEXAS TEXAS OKLAHOMA TEXAS COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO NEW MEXICO NEW MEXICO NEW MEXICO WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS PENNSYLVANIA COLORADO COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS UTAH TEXAS TEXAS TEXAS TEXAS TEXAS Rig 247 248 249 250 251 252 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 292 293 294 295 296 297 298 299 300 301 302 303 Optimum Depth (Feet) 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 8,000 8,000 8,000 12 Rig Type 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) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) Drawworks: Horsepower 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 1,150 1,150 1,150 Location TEXAS TEXAS TEXAS WYOMING WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS TEXAS WYOMING COLORADO TEXAS COLORADO COLORADO COLORADO COLORADO COLORADO WYOMING COLORADO COLORADO COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS NEW MEXICO TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS CALIFORNIA CALIFORNIA COLORADO COLORADO NEW MEXICO MISSISSIPPI TEXAS TEXAS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA CALIFORNIA CALIFORNIA LOUISIANA TEXAS Rig 304 305 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 323 324 325 326 327 328 329 330 331 332 340 341 342 343 344 345 346 347 348 349 351 352 370 371 372 373 374 375 376 377 378 379 380 381 382 383 Optimum Depth (Feet) 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 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 8,000 14,000 14,000 14,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 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 Rig Type 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) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) 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) Drawworks: Horsepower 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 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 1,500 1,500 1,500 1,150 1,150 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 Location TEXAS PENNSYLVANIA TEXAS MISSISSIPPI TEXAS LOUISIANA LOUISIANA LOUISIANA LOUISIANA LOUISIANA TEXAS HIGHLY MOBILE RIGS ARKANSAS OKLAHOMA TEXAS WYOMING OKLAHOMA TEXAS OKLAHOMA TEXAS TEXAS TEXAS UTAH CONVENTIONAL RIGS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS LOUISIANA OKLAHOMA TEXAS NORTH DAKOTA LOUISIANA TEXAS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS TEXAS TEXAS LOUISIANA OKLAHOMA TEXAS LOUISIANA TEXAS TEXAS LOUISIANA LOUISIANA Rig 384 385 387 388 389 391 394 395 397 398 417 140 158 156 159 141 142 143 145 155 146 154 110 96 118 119 120 122 162 171 172 79 80 89 92 94 98 97 99 137 149 72 73 125 134 136 157 161 163 Optimum Depth (Feet) 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 Rig Type AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) Drawworks: Horsepower 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Mechanical SCR Mechanical Mechanical Mechanical Mechanical Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 900 900 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 1,700 1,500 1,500 1,500 2,000 1,500 1,500 1,500 1,500 1,500 2,000 2,000 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 10,000 10,000 12,000 12,000 14,000 14,000 14,000 14,000 14,000 16,000 16,000 12,000 16,000 16,000 16,000 16,000 16,000 18,000 18,000 18,000 20,000 20,000 20,000 20,000 20,000 20,000 26,000 26,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 14 Location OFFSHORE PLATFORM RIGS Rig Optimum Depth (Feet) Rig Type Drawworks: Horsepower TRINIDAD GULF OF MEXICO LOUISIANA GULF OF MEXICO GULF OF MEXICO LOUISIANA GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO 203 205 206 100 105 107 201 202 204 20,000 20,000 20,000 30,000 30,000 30,000 30,000 30,000 30,000 Self-Erecting Self-Erecting Self-Erecting Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 2,500 2,000 1,500 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of our U.S. land and offshore drilling rigs for the periods indicated: Years ended September 30, 2005 2006 2007 2008 2009 U.S. Land Rigs Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1) . . . . . . . . . . . . . . . . . . . . . U.S. Offshore Platform Rigs Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1) . . . . . . . . . . . . . . . . . . . . . 113 91 94% 99% 97% 96% 68% 185 157 201 9 11 9 53% 69% 65% 75% 89% 9 9 (1) A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract. 15 The following table sets forth certain information concerning our international drilling rigs as of September 30, 2009: Location Africa* Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina* Argentina* Colombia Colombia Colombia Colombia Colombia Colombia Ecuador Ecuador Ecuador Ecuador Mexico Mexico Mexico Mexico Mexico Mexico Texas# Texas^ Texas^ Texas^ Texas^ Texas^ Tunisia Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 228 123 139 151 175 177 335 336 337 338 133 152 176 190 333 334 117 121 132 138 230 231 234 237 245 253 339 220 224 232 235 238 242 113 115 116 127 128 129 135 150 153 160 174 Optimum Depth (Feet) Rig Type Drawworks: Horsepower 18,000 26,000 30,000+ 30,000+ 30,000 30,000 8,000 8,000 8,000 8,000 30,000 30,000+ 18,000 26,000 8,000 8,000 26,000 20,000 18,000 26,000 18,000 18,000 18,000 18,000 18,000 18,000 8,000 18,000 18,000 18,000 18,000 18,000 18,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 26,000 30,000 AC (FlexRig3) SCR SCR SCR SCR SCR AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) SCR SCR SCR SCR AC (FlexRig4) AC (FlexRig4) SCR SCR SCR SCR AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig4) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 1,500 2,100 3,000 3,000 3,000 3,000 1,150 1,150 1,150 1,150 3,000 3,000 1,500 2,000 1,150 1,150 2,500 1,700 1,500 2,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 1,500 1,500 1,500 1,500 1,500 1,500 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 2,000 3,000 * En route to drilling location in Africa at September 30, 2009 # Rig under contract with location to be determined by operator ^ Rig being used for prospective bidding purposes 16 The following table sets forth information with respect to the utilization of our international drilling rigs for the periods indicated: Years ended September 30, 2005 2006 2007 2008 2009 Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1)(2) . . . . . . . . . . . . . . . . . . . . . 27 26 27 77% 90% 90% 82% 68% 30 44 (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. STOCK PORTFOLIO Information required by this item regarding our stock portfolio may be found on, and is incorporated by reference to, page 27 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’ Item 3. LEGAL PROCEEDINGS In our prior filings with the Securities and Exchange Commission (‘‘SEC’’), we disclosed that in connection with our Foreign Corrupt Practices Act training, questions were raised about the legality of certain past payments by one of our subsidiaries in connection with the passage of materials through customs in Latin America. In consultation with the Audit and the Nominating and Corporate Governance Committees of the Board of Directors, we engaged outside counsel and outside accountants to review these payments, other transactions of the subsidiary, and transactions at certain of our other operations in Latin America. We voluntarily reported this matter and the results of our investigations to the SEC and the Department of Justice (‘‘DOJ’’) to inform them of this matter. On July 30, 2009, the SEC and the DOJ publicly announced the settlement of the matter. In connection with the SEC settlement, we agreed to cease and desist from committing or causing any violations of the books and records and internal controls provisions of sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’), and agreed to pay $375,681.22 in disgorgement and prejudgment interest to the SEC. In addition, we entered into a non-prosecution agreement with the DOJ in which the DOJ agreed not to prosecute the Company or our subsidiaries or affiliates and we agreed to pay a civil penalty of $1,000,000 to the DOJ. In connection with the settlements, we agreed to take additional remedial action to further enhance our compliance programs. There were no criminal charges involved in the settlements and we took disciplinary action with respect to certain employees involved in the matter, including in some cases, termination of employment. Both settlements recognize our voluntary disclosure, cooperation with both agencies, and our proactive remedial efforts. We are subject to various claims that arise in the ordinary course of our business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect our business, financial position and results of operations. We are not a party to, and none of our property is subject to, any material pending legal proceedings. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 17 OUR EXECUTIVE OFFICERS The following table sets forth the names and ages of our 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, 86 Chairman of the Board since 1960; Director since 1949 Hans Helmerich, 51 . . . President and Chief Executive Officer since 1989; Director since 1987 Douglas E. Fears, 60 . . . Executive Vice President and Chief Financial Officer since June 2008; Vice President and Chief Financial Officer since 1988 Steven R. Mackey, 58 . . Executive Vice President, Secretary and General Counsel since June 2008; Secretary since 1990; Vice President and General Counsel since 1988 John W. Lindsay, 48 . . . Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. since 2006; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. since 1997 M. Alan Orr, 58 . . . . . . 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. since 1992 Gordon K. Helm, 56 . . . Vice President and Controller. Vice President since 2008; Controller since 1993 18 PART II Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The principal market on which our 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 2008 2009 High Low High Low First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $40.60 47.89 77.24 75.38 $29.49 32.86 45.57 39.33 $43.27 28.93 37.19 41.08 $17.01 19.50 21.76 26.64 We paid quarterly cash dividends during the past two years as shown in the following table: Quarter Paid per Share Total Payment Fiscal Fiscal 2008 2009 2008 2009 First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $.045 .045 .045 .050 $.050 .050 .050 .050 $4,678,511 4,685,576 4,706,051 5,272,654 $5,273,254 5,274,814 5,281,430 5,281,580 Payment of future dividends will depend on earnings and other factors. As of November 19, 2009, there were 663 record holders of our common stock as listed by the transfer agent’s records. 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 and Analysis of Financial Condition and Results of Operations contained on pages 6 through 81 of our 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 2005 2006 2007 2008 2009 Operating revenues . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . Income from continuing operations per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . Cash dividends declared per common $ 800,726 127,606 (in thousands except per share amounts) $1,629,658 449,261 $1,224,813 293,858 $2,036,543 461,738 $1,894,038 353,545 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 4.43 4.34 3,588,045 475,000 3.36 3.32 4,161,024 420,000 share . . . . . . . . . . . . . . . . . . . . . . . . . . 0.165 0.1725 0.18 0.185 0.20 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 6 through 41 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’ 19 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found under the caption ‘‘Risk Factors’’ beginning on page 6 of this Report and on, and is incorporated by reference to, the following pages of our Annual Report (Exhibit 13 to this Form 10-K) under Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to Consolidated Financial Statements: Market Risk (cid:129) Foreign Currency Exchange Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Credit Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Commodity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Interest Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Equity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 36 38 39 40 41 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found on, and is incorporated by reference to, pages 43 through 81 of our Annual Report (Exhibit 13 to this Form 10-K). Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 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, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our 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, 2009. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that: (cid:129) our disclosure controls and procedures are effective at ensuring that information required to be disclosed by us in the reports we file or submit 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:129) our 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 our management, and made known to our 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 on Internal Control over Financial Reporting. Our management 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. Our 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. Our 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 our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting 20 principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our 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 our Chief Executive Officer and Chief Financial Officer, conducted an 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 this evaluation, management has concluded that our internal control over financial reporting was effective as of September 30, 2009. The independent registered public accounting firm that audited our financial statements, Ernst & Young LLP, has issued an attestation report on our internal control over financial reporting. This report appears below at the end of this Item 9A of Form 10-K. c) Changes in Internal Control Over Financial Reporting There were no changes in our internal control over financial reporting during our fourth fiscal quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. * * * 21 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, 2009, 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 on 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, 2009, 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, 2009 and 2008 and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2009 of Helmerich & Payne, Inc. and our report dated November 24, 2009 expressed an unqualified opinion thereon. /S/ Ernst & Young LLP Tulsa, Oklahoma November 24, 2009 22 Item 9B. OTHER INFORMATION None. 23 PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required by this item is incorporated herein by reference to the material under the captions ‘‘Proposal 1—Election of Directors,’’ ‘‘Committees,’’ ‘‘Corporate Governance’’ and ‘‘Section 16(a) Beneficial Ownership Reporting Compliance’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. Information required under this item with respect to executive officers under Item 401 of Regulation S-K appears under ‘‘Our Executive Officers’’ in Part I of this Form 10-K. We have adopted a Code of Ethics for Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under ‘‘Corporate Governance.’’ Our Internet address is www.hpinc.com. We intend to disclose any amendments to or waivers from this code on our website. Item 11. EXECUTIVE COMPENSATION The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation is incorporated herein by reference to the material beginning with the caption ‘‘Executive Compensation Discussion and Analysis’’ and ending with the caption ‘‘Potential Payments Upon Termination’’, as well as under the captions ‘‘Director Compensation in Fiscal 2009’’ and ‘‘Compensation Committee Interlocks and Insider Participation’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item is incorporated herein by reference to the material under the captions ‘‘Summary of All Existing Equity Compensation Plans,’’ ‘‘Security Ownership of Certain Beneficial Owners’’ and ‘‘Security Ownership of Management’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item is incorporated herein by reference to the material under the captions ‘‘Transactions With Related Persons, Promoters and Certain Control Persons’’ and ‘‘Corporate Governance’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by this item is incorporated herein by reference to the material under the caption ‘‘Audit Fees’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. 24 Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV a) 1. Financial Statements: The following appear in our Annual Report to Stockholders (Exhibit 13 to this Form 10-K) 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, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 42 43 Consolidated Balance Sheets at September 30, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . 44-45 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 47 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48-81 2. Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto. 3. Exhibits. The following documents are included as exhibits to this Annual Report on Form 10-K. Exhibits incorporated by reference are duly noted as such. 3.1 3.2 4.1 4.2 *10.1 *10.2 *10.3 *10.4 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. 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. 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. 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. 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. 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. 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. Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Appendix ‘‘A’’ of the Company’s Proxy Statement on Schedule 14A filed on January 27, 1997. 25 *10.5 *10.6 *10.7 *10.8 *10.9 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. 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. Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Appendix ‘‘A’’ of the Company’s Proxy Statement on Schedule 14A filed on January 26, 2001. 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. Form of Director Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2000 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. *10.10 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. 10.11 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221. 10.12 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. 10.13 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. 10.14 First Amendment to Lease between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 29, 2008. *10.15 Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 6, 2007, SEC File No. 001-04221. *10.16 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. *10.17 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. 26 10.18 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. 10.19 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. 10.20 Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.33 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221. 10.21 Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221. *10.22 *10.23 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. 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 December 31, 2008, SEC File No. 001-04221. Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221. *10.24 Helmerich & Payne, Inc. Director Deferred Compensation Plan 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 December 31, 2008, SEC File No. 001-04221. *10.25 Amended form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2005 Long-Term 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 March 31, 2009, SEC File No. 001-04221. 10.26 364-Day Credit Agreement dated January 21, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, is incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed January 22, 2009, SEC File No. 001-04221. 10.27 Note Purchase Agreement dated as of June 15, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various Note purchasers is incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed July 21, 2009, SEC File No. 001-04221. 13. 21. 23.1 31.1 31.2 The Company’s Annual Report to Shareholders for fiscal 2009. List of Subsidiaries of the Company. Consent of Independent Registered Public Accounting Firm. 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. 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. 27 32. 101. 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. Financial statements from the annual report on Form 10-K of Helmerich & Payne, Inc. for the fiscal year ended September 30, 2009, filed on November 25, 2009, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements tagged as blocks of text. * Management or Compensatory Plan or Arrangement. 28 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 25, 2009 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/ RANDY A. FOUTCH William L. Armstrong, Director Date: November 25, 2009 Randy A. Foutch, Director Date: November 25, 2009 By /s/ HANS HELMERICH By /s/ W. H. HELMERICH, III Hans Helmerich, Director & CEO Date: November 25, 2009 W. H. Helmerich, III, Director Date: November 25, 2009 By /s/ PAULA MARSHALL By /s/ FRANCIS ROONEY Paula Marshall, Director Date: November 25, 2009 Francis Rooney, Director Date: November 25, 2009 By /s/ EDWARD B. RUST, JR. By /s/ JOHN D. ZEGLIS Edward B. Rust, Jr., Director Date: November 25, 2009 John D. Zeglis, Director Date: November 25, 2009 By /s/ DOUGLAS E. FEARS By /s/ GORDON K. HELM Douglas E. Fears (Principal Financial Officer) Date: November 25, 2009 Gordon K. Helm (Principal Accounting Officer) Date: November 25, 2009 29 I, Hans Helmerich, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.; 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 registrant as of, and for, the periods presented in this report; 4. The registrant’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 registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this 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 registrant’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 registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: November 25, 2009 /s/ HANS HELMERICH Hans Helmerich President and Chief Executive Officer 30 I, Douglas E. Fears, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.; 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 registrant as of, and for, the periods presented in this report; 4. The registrant’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 registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this 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 registrant’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 registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: November 25, 2009 /s/ DOUGLAS E. FEARS Douglas E. Fears Executive Vice President and Chief Financial Officer 31 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, 2009 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 Executive 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 25, 2009 /s/ DOUGLAS E. FEARS Douglas E. Fears Executive Vice President and Chief Financial Officer Date: November 25, 2009 32 Management’s Discussion and 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 Part I of our Form 10-K as well as the Consolidated Financial Statements and related notes thereto. Our future operating results may be affected by various trends and factors, which are beyond our 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, disruptions to the global credit markets, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, changes in domestic and foreign policies, laws and regulations and uncertain business conditions that affect our 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 and Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are 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 us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 6 of our 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 33 forward-looking statement made by us or persons acting on our behalf. We undertake no duty to update or revise our 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 254 drilling rigs at September 30, 2009. Our contract drilling segments include the U.S. Land segment in which we had 201 rigs, the Offshore segment in which we had 9 offshore platform rigs, and the International Land segment in which we had 44 rigs at September 30, 2009. As oil and natural gas prices steeply declined and the credit markets tightened in late calendar 2008, customers aggressively reduced drilling budgets. As a result, we experienced a decline in rig utilization in the U.S. Land segment and in some countries in the International Land segment. We believe that utilization has stabilized and is now slowly improving. During this cycle, we have had the opportunity to attract new customers. Additionally, we are seeing opportunities for expansion in international markets as we entered Mexico and placed a second rig in Africa during the fiscal year. We have also penetrated new markets in the U.S. Drilling has become more challenging with growing unconventional plays, requiring more highly capable rigs which are expected to be in short supply as demand improves. With our fleet that includes 183 FlexRigs with advanced technology, we are well positioned to meet the long-term needs of our customers and compete successfully for opportunities in an improving market. RESULTS OF OPERATIONS All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2009 34 was $353.5 million ($3.32 per share), compared with $461.7 million ($4.34 per share) for 2008 and $449.3 million ($4.27 per share) for 2007. Included in our net income were after-tax gains from the sale of investment securities of $13.5 million ($0.13 per share) in 2008 and $40.2 million ($0.38 per share) in 2007. Net income also includes after-tax gains from the sale of assets of $3.6 million ($0.04 per share) in 2009, $8.6 million ($0.08 per share) in 2008 and $26.5 million ($0.25 per share) in 2007. Included in net income in 2009 and 2008 are after-tax gains of $0.3 million and $6.5 million ($0.06 per share), respectively, 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 our portion of income from an equity affiliate, Atwood Oceanics, Inc. (Atwood), of $0.09 per share in 2009, $0.16 per share in 2008 and $0.09 per share in 2007. Effective April 1, 2009, we determined we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes deferred as a component of other comprehensive income. Consolidated operating revenues were $1,894.0 million in 2009, $2,036.5 million in 2008, and $1,629.7 million in 2007. During 2007 and 2008, U.S. land revenues increased due to the addition of FlexRigs combined with continued increases in dayrates since 2005. In 2009, as oil and natural gas prices declined and uncertainty in the capital markets increased, customers reduced spending on exploration and development drilling causing a reduction in rig utilization. Our U.S. land rig utilization was 68 percent in 2009, 96 percent in 2008 and 97 percent in 2007. The average number of U.S. land rigs available was 194 rigs in 2009, 171 rigs in 2008 and 134 rigs in 35 2007. Revenue in the Offshore segment increased over the three-year period primarily as a result of rig utilization for offshore rigs increasing to 89 percent in 2009, compared to 75 percent in 2008 and 65 percent in 2007. International rig revenues decreased in 2009 after increasing in 2008 from 2007. Contributing to the decrease in revenue in 2009 was the discontinuation of recording revenue in Venezuela for the last three fiscal quarters of 2009. Additionally, rig utilization in 2009 declined to 68 percent as we discontinued work in Venezuela as contracts expired. For further detail regarding Venezuela, see the International Land segment below and Note 14 of the Consolidated Financial Statements. The increase in revenue in 2008 from 2007 was due to increases in dayrates even though rig utilization declined in 2008 to 82 percent from 90 percent in 2007. We did not sell any investment securities in 2009, but recorded gains of $22.0 million in 2008 and $65.5 million in 2007. Interest and dividend income was $5.0 million in 2009 and 2008 and $4.2 million in 2007. Direct operating costs in 2009 were $1,011.6 million, compared with $1,086.7 million in 2008 and $862.3 million in 2007. Direct operating costs for all three years were 53 percent of operating revenues. Depreciation expense was $236.4 million in 2009, $210.8 million in 2008 and $146.0 million in 2007. Included in depreciation are abandonments of equipment of $5.3 million in 2009, $13.3 million in 2008, and $4.1 million in 2007. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 25 new rigs in 2009, 29 in 2008 and 48 in 2007. Depreciation expense in 2010 is expected to increase from 2009 from 36 new rigs placed into service during 2009 and additional rigs placed into service during 2010. (See Liquidity and Capital Resources) As conditions warrant, management performs an analysis of the industry market conditions in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2009, 2008 and 2007, no impairment was recorded. General and administrative expenses totaled $59.4 million in 2009, $57.1 million in 2008, and $47.4 million in 2007. The $2.3 million increase in 2009 from 2008 is primarily due to an increase in banking and legal fees associated with obtaining new debt, increased pension expense and services associated with the FCPA investigation and settlement discussed further in Item 3 Legal Proceedings of our Form 10-K. These increases were partially offset with a decrease in current year employee bonus accruals. The increase in 2008 from 2007 was primarily a result of increases in expenses associated with employee labor and employee benefits due to increases in the number of employees. Interest expense was $13.5 million in 2009, $18.7 million in 2008, and $10.1 million in 2007. The interest expense is primarily attributable to the fixed-rate intermediate debt outstanding in each year and advances on the senior credit facility in 2009 and 2008. Interest expense decreased in 2009 from 2008 primarily as a result of reduced interest rates. Interest expense in 2008 increased from 2007 due to higher outstanding debt balances during 2008. Capitalized interest was $6.6 million, $4.7 million and $9.4 million in 2009, 2008 and 2007, respectively. All of the capitalized interest is attributable to our rig build program. The higher capitalized interest 37 in 2007 was due to a higher number of new rigs being constructed during that year. The provision for income taxes totaled $232.4 million in 2009, $255.6 million in 2008, and $251.0 million in 2007. The effective income tax rate increased to 40 percent in 2009 from 37 percent in 2008, and 36 percent in 2007. The increase in the effective tax rate is primarily due to Venezuelan income taxes being calculated using the accrual method of accounting for financial purposes while we are recognizing revenue in Venezuela using the cash basis method of accounting. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management’s judgments using certain estimates and assumptions that we 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 may 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.) On May 21, 2008, we acquired a private limited partnership, TerraVici Drilling Solutions (TerraVici) in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets and liabilities of TerraVici were recorded as of the acquisition date, at their respective fair values, and consolidated with our financial statements. The operations for TerraVici are included with all other non-reportable business segments. 38 TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with FlexRigs. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer. We paid a total purchase price of $12.2 million, including acquisition related fees of $1.2 million. In conjunction with the acquisition, we recorded an in-process research and development (IPR&D) charge of $11.1 million in 2008. The IPR&D represents rotary steerable system (RSS) tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. The $11.1 million estimated fair value of the IPR&D was derived using the multi-period excess- earnings method. The terms of the transaction provide for future contingency payments up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met. During 2009 and 2008, we incurred $9.7 million and $1.8 million, respectively, of research and development expenses related to ongoing development of the RSS. We anticipate research and development expenses to be approximately $2.5 million in each quarter during 2010. The following tables summarize operations by reportable operating segment. 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 9 A N D 2 0 0 8 2009 2008 % Change U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation (in thousands, except operating statistics) $1,441,164 $1,542,038 663,385 16,812 187,259 756,828 17,599 161,893 Segment operating income $ 573,708 $ 605,718 Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 48,055 28,194 12,009 16,185 $ $ $ 201 68% 59,804 24,522 11,393 13,129 $ $ $ 185 96% (6.5)% (12.4) (4.5) 15.7 (5.3) (19.7)% 15.0 5.4 23.3 8.6 (29.2) Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $86,297 and $75,519 for 2009 and 2008, respectively. Rig utilization excludes seven FlexRigs completed and ready for delivery at September 30, 2009. Operating income in the U.S. Land segment decreased to $573.7 million in 2009 from $605.7 million in 2008. Included in U.S. land revenues for 2009 is approximately $169.4 million from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. The average revenue per day for 2009 increased $3,672 of which $3,524 is attributable to the early termination related revenue and customer requested delivery delay revenue for new FlexRigs. During 2009, we received 37 early termination notices from customers corresponding to the new rig build program. All 37 rigs released had been deployed to the field prior to fiscal 2008. Direct operating expenses decreased 12.4 percent from 2008 to 2009, and the expense as a percentage of revenue declined to 46 percent in 2009 from 49 percent in 2008. The average rig expense per day, however, increased during 2009 due to fixed expenses incurred on 40 idle rigs including property taxes and insurance as well as labor and other expenses associated with stacking rigs. Rig utilization decreased to 68 percent in 2009 from 96 percent in 2008. The total number of rigs at September 30, 2009 was 201 compared to 185 rigs at September 30, 2008. The net increase is due to 22 new FlexRigs having been completed and placed into service, 7 rigs completed and ready for service, 7 transferred to the International Land segment with customer commitments, 5 transferred to the International Land segment to be used for bidding prospective work, and 1 rig removed and held for sale. Depreciation includes charges for abandoned equipment of $4.9 million and $13.2 million in 2009 and 2008, respectively. Excluding the abandonment amounts, depreciation in 2009 increased 23 percent from 2008 due to the increase in available rigs. We expect to complete and deliver another seven new FlexRigs by the end of the third fiscal quarter of 2010. Like those completed in fiscal 2009, each of these new rigs is committed to work for an exploration and production company under a fixed term contract, performing drilling services on a daywork contract basis. As a result of the new FlexRigs added in 2009 and additional rigs scheduled for completion in 2010, we anticipate depreciation expense to continue to increase in fiscal 2010. During 2009, the economic recession, including the decrease in oil and natural gas prices and deterioration in the credit markets, had a significant effect on customer spending and drilling activity. As a result, the industry’s active land drilling rig count in the U.S. land market declined by over fifty percent from the Fall of 2008 to the Summer of 2009. Although not as severe as that experienced by most 41 of our peers, we experienced a significant decline in drilling activity. Since June 2009, however, the industry’s U.S. land rig count has been experiencing a slight recovery. At September 30, 2009, 122 out of 201 existing rigs in the U.S. Land segment were generating revenue. Of the 122 rigs generating revenue, 94 were under fixed term contracts, and 28 were working in the spot market. At November 19, 2009, the number of existing rigs under fixed term contracts in the segment increased to 96, and the number of rigs working in the spot market increased to 31. 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 9 A N D 2 0 0 8 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 rigs at end of period Rig utilization 2009 2008 % Change (in thousands, except operating statistics) $204,702 133,442 4,095 11,872 $ 55,293 2,938 $ 48,677 $ 27,373 $ 21,304 9 89% $154,452 104,454 4,452 12,152 $ 33,394 2,442 $ 47,743 $ 29,655 $ 18,088 9 75% 32.5% 27.8 (8.0) (2.3) 65.6 20.3% 2.0 (7.7) 17.8 — 18.7 Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $34,125 and $16,330 for 2009 and 2008, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in our Offshore segment increased 66 percent in 2009 from 2008 due to higher activity including a rig that began work in Trinidad during 2008. Currently, we have seven of our nine platform rigs working. One of the seven rigs is expected to become idle during the first quarter of 42 fiscal 2010 and one of the two idle rigs began work under a new contract in November 2009. 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 9 A N D 2 0 0 8 INTERNATIONAL LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income (loss) Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2009 2008 % Change (in thousands, except operating statistics) $237,397 213,552 2,892 28,180 $ (7,227) 7,374 $ 29,650 $ 25,993 $ 3,657 44 68% $328,244 224,683 3,974 29,614 $ 69,973 8,026 $ 37,604 $ 24,489 $ 13,115 30 82% (27.7)% (5.0) (27.2) (4.8) (110.3) (8.1)% (21.2) 6.1 (72.1) 46.7 (17.1) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $18,755 and $26,431 for 2009 and 2008, respectively. Also excluded are the effects of currency revaluation expense. Rig utilization at September 30, 2009 excludes one FlexRig completed and ready for delivery and two FlexRigs delivered waiting on customer location. Rig utilization at September 30, 2008 excludes four FlexRigs completed and ready for delivery. The International Land segment had an operating loss of $7.2 million for 2009 compared to operating income of $70.0 million for 2008. As further discussed in Note 14 of the Consolidated Financial Statements, we determined that as of the beginning of the second quarter of fiscal 2009 and forward, services to our customer in Venezuela, Petroleos de Venezuela, S.A. (PDVSA), no longer met the revenue recognition criteria as collectability became uncertain. As a result, $57.9 million of revenue was not recorded during 2009. Primarily because of this change, revenue and average revenue per day decreased in 2009 compared to 2008. Revenues not recognized in 2009 will be recognized in future periods when cash is collected. 43 Rig utilization for international land operations decreased to 68 percent in 2009 from 82 percent in 2008. The ability to collect accounts receivables in U.S. dollars from PDVSA deteriorated to the point that during the second fiscal quarter of 2009, we decided to discontinue work as contracts expired. All of our eleven rigs in Venezuela were active at the end of 2008. At the end of 2009, one rig remained active and has since become idle. During 2009, 12 rigs were transferred to the International Land segment from the U.S. Land segment. Of those twelve, seven are under contract and the remaining five are being used for bidding prospective work. The reduced activity in Venezuela and rigs transferred to the segment that are not yet working contributed to the decrease in utilization. The total number of rigs at September 30, 2009 was 44 compared to 30 rigs at September 30, 2008. The increase is due to two FlexRigs completed and ready for delivery and 12 rigs transferred from the U.S. Land segment. Three of the FlexRigs completed in 2008 were placed into service in 2009. The fourth rig completed in 2008 is under contract and will be sent to a location to be determined by the operator. The average rig expense per day increased in 2009 from 2008 primarily due to labor and stacking expenses related to rigs that became idle during 2009. We will continue to pursue future drilling opportunities in Venezuela, but do not expect to commit to new contracts until additional progress is made on unpaid invoices and converting local currency to U.S. dollars. 44 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 8 A N D 2 0 0 7 2008 2007 % Change U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation (in thousands, except operating statistics) $1,542,038 $1,174,956 756,828 17,599 161,893 587,825 14,024 106,107 Segment operating income $ 605,718 $ 467,000 Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 59,804 24,522 11,393 13,129 $ $ $ 185 96% 47,338 23,573 11,170 12,403 $ $ $ 157 97% 31.2% 28.8 25.5 52.6 29.7 26.3% 4.0 2.0 5.9 17.8 (1.0) Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $75,519 and $59,035 for 2008 and 2007, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007. Operating income in the U.S. Land segment increased to $605.7 million in 2008 from $467.0 million in 2007. Improvement in revenue was primarily the result of increased revenue days and increased dayrates for new rigs placed in service during 2008. Rig utilization decreased to 96 percent in 2008 from 97 percent in 2007. At September 30, 2008, two conventional rigs and one highly mobile rig were stacked. The total number of rigs at September 30, 2008 was 185 compared to 157 rigs at September 30, 2007. The increase was due to 28 new FlexRigs being completed and placed into service. Depreciation included charges for abandoned equipment of $13.2 million and $2.3 million in 2008 and 2007, respectively. Excluding the abandonment amounts, depreciation in 2008 increased 43.2 percent from 2007 due to the increase in available rigs. 45 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 8 A N D 2 0 0 7 2008 2007 % Change 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 rigs at end of period Rig utilization $154,452 104,454 4,452 12,152 $ 33,394 2,442 $ 47,743 $ 29,655 $ 18,088 9 75% (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% 25.4% 22.1 (7.7) 13.7 51.2 14.1% 38.5 37.5 40.2 — 15.4 Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $16,330 and $14,328 for 2008 and 2007, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in our Offshore segment increased 51.2 percent in 2008 from 2007 due to increased activity and a rig beginning work in Trinidad. 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 8 A N D 2 0 0 7 2008 2007 % Change INTERNATIONAL LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income (loss) Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization $328,244 224,683 3,974 29,614 $ 69,973 8,026 $ 37,604 $ 24,489 $ 13,115 30 82% (in thousands, except operating statistics) $320,283 188,086 3,236 23,782 $105,179 8,886 $ 31,465 $ 16,708 $ 14,757 27 90% 2.5% 19.5 22.8 24.5 (33.5) (9.7)% 19.5 46.6 (11.1) 11.1 (8.9) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $26,431 and $40,113 for 2008 and 2007, respectively. Also excluded are the effects of currency revaluation expense. Rig utilization excludes four FlexRigs completed and ready for delivery at September 30, 2008. 46 Segment operating income for our International Land segment decreased 33.5 percent from 2007 to 2008. Depreciation and operating income for 2008 were negatively impacted by an adjustment of approximately $5.9 million related to prior years’ depreciation. Rig utilization for international land operations decreased to 82 percent in 2008 from 90 percent in 2007. Direct operating expenses increased in 2008 from 2007 as oilfield cost inflation pressures and labor cost increases in the international markets were experienced. LIQUIDIT Y AND CAPITAL RESOURCES Our capital spending was $880.8 million in 2009, $705.6 million in 2008, and $894.2 million in 2007. Net cash provided from operating activities was $897.3 million in 2009, $610.8 million in 2008 and $561.1 million in 2007. Our 2010 capital spending estimate is approximately $225 million, a decrease from the $881 million incurred during 2009. The primary reason for the decrease in estimated capital expenditures is that only seven contracted new FlexRigs are scheduled to be completed during 2010, a significant reduction in the number of new rigs built compared to 2009. Historically, we have financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, we will either borrow from available credit sources or, if market conditions are favorable, sell portfolio securities. Likewise, if we are generating excess cash flows, we may invest in short-term investments. In 2009, we purchased $12.5 million of short-term investments. We manage a portfolio of marketable securities that, at the close of fiscal 2009, had a market value of $359.5 million. Our investments 47 in Atwood and Schlumberger, Ltd. made up 95 percent of the portfolio’s market value on September 30, 2009. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet. We generated cash proceeds from the sale of portfolio securities of $25.5 million in 2008 and $73.4 million in 2007. We did not sell any portfolio securities in 2009. 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 our Consolidated Financial Statements: Proceeds from the sale of portfolio securities 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 Statements of Cash Flows 2009 $— — — $— 2008 (in thousands) $25,507 — — 2007 $ 73,405 6,093 48,321 $25,507 $127,819 In 2008, proceeds were from the sale of 170,000 shares of Schlumberger, Ltd. and all other available-for-sale securities we owned. In 2007, proceeds were primarily from the sale of 1,012,500 shares of Schlumberger, Ltd. Proceeds in both years were primarily used to fund capital expenditures. Our proceeds from asset sales totaled $8.7 million in 2009, $22.9 million in 2008 and $51.6 million in 2007. In 2008, two international land rigs were sold generating $13.0 million in 48 proceeds. Income from asset sales in 2008 totaled $13.5 million. In 2007, one U.S. land rig and two offshore rigs were sold generating $36.7 million in proceeds. Income from all asset sales in 2007 totaled $41.7 million. The rigs sold in each year were idle at the time of the sales and, with our emphasis on FlexRig technology, we took advantage of the opportunity to sell older rigs. In each year we also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business. In 2009, 2008 and 2007, we received insurance proceeds of approximately $0.2 million, $5.3 million and $19.2 million, respectively, for damages sustained to our offshore Rig 201 during Hurricane Katrina. During the fourth quarter of fiscal 2007, our Rig 178 was lost when the well it was drilling had a blowout. During 2009 and 2008, we received gross insurance proceeds of approximately $0.3 million and $8.7 million, respectively, in connection with the loss of Rig 178. We recorded a net gain from involuntary conversion of approximately $0.5 million in 2009, $10.2 million in 2008 and $16.7 million in 2007. The proceeds, shown in the Consolidated Statements of Cash Flows under investing activities, were used to rebuild Rig 201 and replace Rig 178. The costs for both rigs were capitalized with Rig 201 returning to work in the fourth fiscal quarter of 2007 and the replacement rig returning to work in 2008. We have settled both claims and no additional insurance proceeds are expected. From March 2005 through November 2008, we announced commitments with exploration and production companies to build a cumulative total of 140 new FlexRigs under fixed term contracts to perform drilling services on a daywork basis. Eight of these 140 new rigs were contracted for work in International Land operations and 49 the remaining 132 in U.S. Land operations. We completed 133 of the 140 rigs through fiscal 2009 and have seven remaining new FlexRigs to complete by the end of the third fiscal quarter of 2010. The total estimated construction cost of all 140 rigs, including tubular and other ancillary equipment, is currently $2.2 billion, most of which was spent by the end of fiscal 2009. We have $150 million of intermediate-term unsecured debt obligations with staged maturities of $75 million in August, 2012 and $75 million in August, 2014. The annual average interest rate through maturity will be 6.50 percent. The terms of the debt obligations require that we maintain a minimum ratio of debt to total capitalization. On July 21, 2009, we closed a private placement of our senior unsecured fixed rate notes maturing in July 2016 and received proceeds of $200 million. Interest on the notes will be paid semi-annually based on an annual rate of 6.10 percent. We will make five equal annual principal repayments of $40 million starting on the third anniversary of the closing date. Financial covenants require that we maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. The $200 million of proceeds from this facility were used to reduce our $400 million senior credit facility by $105 million and the remainder was used to fund capital expenditures and for other general corporate purposes. 50 We have an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility expiring December 2011. We have the option to borrow at the prime rate for maturities of less than 30 days but anticipate the majority of all of the borrowings over the remaining life of the facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). We pay a commitment fee based on the unused balance of the facility. The spread over LIBOR and the commitment fee are determined according to a scale based on the ratio of our 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 2009 fiscal year, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. The advances bear an interest rate of .60 percent. At September 30, 2009, we had two letters of credit totaling $21.9 million under the facility and had borrowed $70 million against the facility with $308.1 million remaining available to borrow. Subsequent to September 30, 2009, we reduced the debt by $30 million and had $338.1 million available to borrow. In January 2009, we closed an agreement with a multi-bank syndicate for a $105 million unsecured line of credit that matures January 2010. We committed to fully fund this facility for the entire term at a spread over 30 day LIBOR. The spread over LIBOR is determined according to the same scale of debt to total capitalization used in our $400 million facility which is described in the preceding paragraph. The spread over LIBOR for the new facility has increased to a range of 2 percent to 2.75 percent. At September 30, 2009, the spread on the borrowing was 2.25 percent over LIBOR. Simultaneous with the closing of this facility, we entered into an interest-rate swap with the same maturity and a notional amount of $105 million. We believe that the swap will act to fix the annualized interest rate of the facility at approximately 3.17 percent assuming the spread remains at 2.25 percent over LIBOR. The interest rate swap qualifies as a 51 derivative and was not designated as a hedging instrument and, as such, we have not applied hedge accounting. At the end of an accounting period, the interest rate swap is recorded in the Consolidated Balance Sheet at fair value, either in other current assets or accrued liabilities, and any related gains or losses are recognized on our Consolidated Statement of Income within interest expense. The fair value of the interest rate swap liability at September 30, 2009 was $0.2 million and is included in accrued liabilities in the Consolidated Balance Sheet. Interest expense on the interest rate swap was $0.6 million during 2009. Financial covenants in both facilities require that we 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. Both facilities contain additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2009, we were in compliance with all debt covenants. At September 30, 2009, we had unsecured letters of credit totaling $3.2 million which were used to obtain surety bonds for our international operations. At September 30, 2009, we had 107 existing rigs with contracts under fixed terms with original term durations ranging from twelve months to seven years, with some expiring in fiscal 2010. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. The 2009 economic slowdown, including the decrease in oil and natural gas prices and deterioration in the credit markets had a significant effect on customer spending. As a result, during 2009 some of our 52 customers exercised termination provisions and elected to pay the early termination fee in lieu of continued drilling. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results would be negatively impacted if this were to happen. Our operating cash requirements and estimated capital expenditures, including completion of the remaining rig construction, for fiscal 2010 will be funded through current cash, cash provided from operating activities, funds available under the current credit facilities, funds available under any new credit facility and, possibly, sales of available-for-sale securities. We anticipate that we will be able to utilize working capital as well as available borrowing capacity under our $400 million line of credit to pay off the $105 million facility when it matures in January 2010. The current ratio was 1.7 at September 30, 2009 and 2.2 at September 30, 2008. The long-term debt to total capitalization ratio was 14 percent and 17 percent at September 30, 2009 and 2008, respectively. The decrease is due to equity increasing, primarily from earnings and a decrease in long-term debt. During 2009, we paid dividends of $0.20 per share, or a total of $21.1 million, representing the 37th consecutive year of dividend increases. 53 STOCK PORTFOLIO HELD September 30, 2009 Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total Number of Shares Cost Basis Market Value (in thousands, except share amounts) 8,000,000 967,500 $121,498 $282,160 7,685 12,369 57,663 19,707 $141,552 $359,530 MATERIAL COMMITMENTS We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2009, are summarized in the table below in thousands: Payments due by year Contractual Obligations Total 2010 2011 2012 2013 2014 After 2014 Long-term debt and estimated interest (a) $517,887 $ 22,385 $22,385 $206,382 $54,205 $126,159 $86,371 Short-term debt and estimated interest (b) 106,041 106,041 Operating leases (c) Purchase obligations (c) 32,182 63,092 8,165 63,092 — 6,145 — — — 3,050 2,569 — — — 2,271 — — 9,982 — Total Contractual Obligations $719,202 $199,683 $28,530 $209,432 $56,774 $128,430 $96,353 (a) The estimated future interest payments on our variable-rate credit facilities were based on the interest rate and principal balance at September 30, 2009. Interest on fixed-rate debt was estimated based on principal maturities. See Note 2 ‘‘Debt’’ to our Consolidated Financial Statements. (b) Estimated interest was calculated based on the interest rate at September 30, 2009 and includes the value of an interest rate swap liability at September 30, 2009. See Note 2 ‘‘Debt’’ to our Consolidated Financial Statements. (c) See Note 15 ‘‘Commitments and Contingencies’’ to our Consolidated Financial Statements. The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions. In 2009, we contributed $0.8 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $3.0 million in 2010 to meet the minimum contribution required by law. We expect to make additional contributions to fund distributions in lieu of liquidating pension assets. With the unpredictability in the equity, debt and global markets, it is possible that contributions in fiscal 2010 will be greater 54 than expected. Future contributions beyond 2010 are difficult to estimate due to multiple variables involved. At September 30, 2009, we had $6.9 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 3 to the Consolidated Financial Statements. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Consolidated Financial Statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. These estimates and assumptions are evaluated on an on-going basis. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements. Other significant accounting policies are summarized in Note 1 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. We account for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets 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 55 operations, technology or market conditions, could materially affect our 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 determinations of 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 the results of operations. Impairment of Long-lived Assets Management assesses the potential impairment of our long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. 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. Fair Value of Financial Instruments Fair value is defined as an exit price, which is the price that would be received upon sale of an asset 56 or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date. The degree of judgment utilized in measuring the fair value of assets and liabilities generally correlates to the level of pricing observability. Financial assets and liabilities with readily available, actively quoted prices or for which fair value can be measured from actively quoted prices in active markets generally have more pricing observability and require less judgment in measuring fair value. Conversely, financial assets and liabilities that are rarely traded or not quoted have less price observability and are generally measured at fair value using valuation models that require more judgment. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency of the asset, liability or market and the nature of the asset or liability. The carrying amounts reported in the statement of financial position for current assets and current liabilities qualifying as financial instruments approximate fair value because of the short-term nature of the instruments. Marketable securities are carried at fair value generally determined by quoted market prices. We have categorized financial assets and liabilities measured at fair value into a three-level hierarchy in accordance with Accounting Standards Codification 820-10. (See Note 7 of the Consolidated Financial Statements for disclosures.) Self-Insurance Accruals We self-insure a significant portion of expected 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. We maintain certain other insurance coverage with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates for incurred outstanding liabilities for worker’s compensation, general liability claims and for claims that are incurred but not reported are recorded. Estimates are based on historic experience and statistical methods that we believe are reliable. 57 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. Our wholly-owned captive insurance company, White Eagle Assurance Company, provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles. With the exception of ‘‘named windstorm’’ risk in the Gulf of Mexico, we insure rig and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1 million per occurrence, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering six offshore platform rigs for ‘‘named windstorm’’ risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers two rigs and has a $40 million limit and a $3.5 million deductible. We maintain certain other insurance coverage with deductibles as high as $5 million. Excess insurance is purchased over these coverages to limit our exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred, and, using adjuster’s estimates, our historical loss experience or 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 and related liabilities. 58 Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered from 7.25 percent to 5.42 percent as of September 30, 2009 to reflect changes in the market conditions for high-quality fixed-income investments. 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. We anticipate pension expense in 2010 to increase from 2009 by an estimated $2.1 million. Stock-Based Compensation Historically, we have granted stock-based awards to key employees and non-employee directors as part of their compensation. We estimate 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 our stock, based upon the expected term of the option. We consider 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 59 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 restricted stock is based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2009, unrecognized compensation cost related to unvested restricted stock was $2.2 million. The cost is expected to be recognized over a weighted- average period of 1.5 years. Revenue Recognition Revenues and expenses for 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. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. NEW ACCOUNTING STANDARDS Effective October 1, 2008, we adopted the disclosure requirements of Accounting Standards Codification (ASC) 820-10, Fair Value Measurements and Disclosures issued by the Financial Accounting Standards Board (FASB) in September 2006, which defines fair value, 60 establishes a framework for measuring fair value and expands disclosures about fair value measurements required under other accounting pronouncements, but does not change existing guidance for carrying instruments at fair value. Our adoption of the required portions of ASC 820-10 as of October 1, 2008 did not have a material impact on our financial position, results of operations or cash flows. ASC 820-10-65, Transition related to FASB Staff Position FAS157-2, issued in February 2008, delays the application of ASC 820-10 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), and will be adopted by us beginning the first quarter of fiscal 2010. Our adoption on October 1, 2009 is not expected to have a significant impact on the Consolidated Financial Statements. ASC 825-10, Financial Instruments, permits choosing to measure certain financial assets and liabilities at fair value. We elected not to measure any assets or liabilities at fair value which were not being so measured prior to adopting ASC 820-10 on October 1, 2008. In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (ASU 2009-05). This update provides amendments to ASC 820, Fair Value Measurements and Disclosure, for the fair value measurement of liabilities when a quoted price in an active market is not available. ASU 2009-05 is effective for reporting periods beginning after August 28, 2009, which means that it will be effective for our first quarter beginning October 1, 2009. We do not currently believe this update will have a significant impact on the Consolidated Financial Statements. On October 1, 2009, we adopted the requirements regarding the accounting for income tax benefits of dividends on share-based payment awards. As a result of the adoption, we recognize a realized 61 income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share-based payment awards that are charged to retained earnings as an increase to additional paid-in capital. The adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2008, the FASB issued guidance contained in ASC 260-10-45 to clarify that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method pursuant to ASC 260-10-05, Earnings per Share. We will adopt ASC 260-10-45 October 1, 2009. All prior-period earnings per share data presented will be adjusted retrospectively to conform to the provisions of ASC 260-10-45. We expect the impact, if any, of adopting ASC 260-10-45 to be immaterial on our prior period earnings per share. ASC 715-20-65, Transition related to SFAS 132R-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. The new guidance requires employers of public and nonpublic companies to disclose more information about how investment allocation decisions are made, more information about major categories of plan assets, including concentration of risk and fair-value measurements, and the fair-value techniques and inputs used to measure plan assets. The disclosure requirements are effective for years ending after December 15, 2009. We will adopt the disclosure requirements for the year ended September 30, 2010, on a prospective basis. We do not expect the adoption to have a material impact on the Consolidated Financial Statements. 62 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Foreign Currency Exchange Rate Risk We have operations in several South American countries, Trinidad, Mexico and Africa. With the exception of Argentina and Venezuela, our 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. The exchange rate between the U.S. dollar and the Argentine peso stayed within a narrow range for seven years and then devalued 27 percent during fiscal 2009, resulting in the recording a $2.2 million currency loss. We are exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte (Bsf ) receivable balances and Bsf cash balances. We have an agreement with the Venezuelan state oil company, PDVSA, whereby 60 percent of our billings are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. PDVSA has previously paid U.S. dollar invoices in Bsf which increases our exposure to foreign currency devaluation. In 2008, we received notification from PDVSA that exchange of those U.S. dollar invoices previously paid in Bsf would be made only when supporting documentation had been approved. The supporting documentation was delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $37.5 million. We are unable to determine when payment will be received. Since 2005, the Venezuelan government has had exchange controls that fix the exchange rate at 2.15 Bsf to one U.S. dollar and also prohibits us, as well as other companies, from converting the Bsf into U.S. dollars. Since that time, we have, in compliance with applicable regulations, submitted three separate requests to the Venezuelan government seeking permission to convert existing Bsf balances into U.S. dollars. All three requests were approved by the Venezuelan 63 government and we were permitted to remit U.S. dollars as dividends from the Venezuelan subsidiary to the U.S. based parent. These dividends reduced our exposure to currency devaluation in Venezuela. On July 22, 2008, we submitted another application with the Venezuelan government requesting the approval to convert Bsf cash balances to U.S. dollars. When and if we receive approval from the Venezuelan government, our Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent as cash balances permit. While we have been successful in obtaining government approval for conversion of Bsf 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 Bsf cash balances could increase and we would be exposed to increased risk of devaluation. Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Venezuela continues to operate under exchange controls and the Venezuelan Bsf exchange rate has remained fixed at 2.15 Bsf to one U.S. dollar since March 2005. The exact amount and timing of any future devaluations attributable to the Venezuelan Bsf exchange rate is uncertain. At September 30, 2009, we had $45.3 million in cash denominated in Bsf exposed to the risk of currency devaluation. Additionally, we have other current assets including accounts receivable exposed to currency devaluation. While we are unable to predict future devaluation in Venezuela, if fiscal 2010 balance sheet components are similar to fiscal 2009 and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million. We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates 64 exceeding 100 percent in the most recent three-year period. The economy in Venezuela has not been considered to be highly inflationary in the past five years, but it is reasonably possible that Venezuela may be considered highly inflationary again at some time in the future. All of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements. Credit Risk Typically, contract drilling revenues are recognized as services are performed. In U.S. generally accepted accounting principles, one of the basic revenue recognition criteria is that collectability of the revenue is reasonably assured. Our revenue in Venezuela is from providing drilling services to PDVSA, the Venezuelan state-owned petroleum company. We determined, as of the beginning of the second quarter of fiscal 2009 and forward, that the revenue recognition criteria in Venezuela is no longer met as collectability of revenue is not reasonably assured, primarily due to the uncertainty of the timing of collectability as discussed further below. As a result of this change, $57.9 million of revenue was not recorded in the International Land segment during fiscal 2009. Since the beginning of the second quarter of fiscal 2009, approximately $69.3 million (U.S. dollars and U.S. currency equivalent) was collected from PDVSA of which $61.4 million was applicable to the accounts receivable balance at the end of the first fiscal quarter of 2009. As of September 30, 2009, the Consolidated Balance Sheet reflected accounts receivable from PDVSA of $26.6 million. Subsequent to the end of fiscal 2009, additional payments of approximately $20.8 million (U.S. dollars and U.S. currency equivalent) were received through November 19, 2009. Approximately 73 percent of this corresponds to accounts receivable at the end of the first fiscal quarter and the remainder to invoices 65 issued for work performed after the first fiscal quarter of 2009. We do not have enough information to conclude that the remaining receivable balance is not probable of collection. However, there is uncertainty regarding the timing of the collection due to the current political, economic and social instability in Venezuela, the dependence by Venezuela on oil to largely support its economy and the failure of PDVSA to pay many service companies working in Venezuela. The collection of receivables from PDVSA has historically been more difficult and slower than that of other customers in international countries in which we have drilling operations due to PDVSA policies and procedures. 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. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The deterioration in the credit and capital markets in 2008 and the apparent slow, cautious recovery since, could make it 66 difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for drilling services. This reduction in spending could have a material adverse effect on our business, financial condition or operations. We attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could impact future operating costs adversely. Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. We have reduced the impact of fluctuations in interest rates by maintaining a portion of our debt portfolio in fixed-rate debt. At September 30, 2009, the amount of our fixed-rate debt was approximately 83 percent of total debt. The following tables provide information as of September 30, 2009 and 2008 about our 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 9 (dollars in thousands) Fixed-Rate Debt Average Interest Rate Variable Rate Debt Average Interest Rate (a) $ $ 2010 2011 2012 2013 2014 After 2014 Total Fair Value 9/30/09 — $ — $115,000 $40,000 $115,000 $80,000 $350,000 $380,925 — — 6.4% 6.1% 6.5% 6.1% 6.3% — $ — $ 70,000 $ — $ — $ — $ 70,000 $ 70,000 (a) (a) Advances bear interest rate of .60% 67 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 8 ( d o l l a r s i n t h o u s a n d s ) 2009 2010 2011 2012 2013 After 2013 Total Fair Value 9/30/08 Fixed Rate Debt $25,000 $ — $ — $75,000 $ — $75,000 $175,000 $198,000 Average Interest Rate 5.9% — — 6.5% — 6.6% 6.5% Variable Rate Debt $ — $ — $325,000 $ — $ — $ — $325,000 $325,000 Average Interest Rate (a) — — — — — — (a) (b) Advances bear interest rates ranging from 2.84% to 4.06% Equity Price Risk On September 30, 2009, we had a portfolio of securities with a total fair value of $359.5 million. The total fair value of the portfolio of securities was $384.0 million at September 30, 2008. Our investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up 95 percent of the portfolio’s fair value at September 30, 2009. Although we sold portions of our positions in Schlumberger in 2008 and 2007, we make no specific plans to sell securities, but rather sell 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 fair value of our holdings. Except for our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. At November 19, 2009, the total fair value of the portfolio of securities had increased to approximately $387.3 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements. 68 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, 2009 and 2008, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2009, in conformity with U.S. generally accepted accounting principles. As discussed in Note 1 to the consolidated financial statements, effective October 1, 2007, the Company adopted the requirements for accounting for uncertainty in income taxes. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne Inc.’s internal control over financial reporting as of September 30, 2009, 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 24, 2009 expressed an unqualified opinion thereon. / s / E R N S T & Y O U N G L L P Tulsa, Oklahoma November 24, 2009 69 Consolidated Balance Sheets ASSETS CURRENT ASSETS: Cash and cash equivalents Short-term investments September 30, 2009 2008 (in thousands) Accounts receivable, less reserve of $659 in 2009 and $1,331 in 2008 Inventories Deferred income taxes Assets held for sale Prepaid expenses and other Total current assets $ 141,486 $ 121,513 12,500 246,790 44,723 12,861 1,023 63,549 522,932 — 462,833 33,098 21,939 — 51,264 690,647 INVESTMENTS 356,404 199,266 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment Construction in progress Real estate properties Other Less-Accumulated depreciation Net property, plant and equipment OTHER ASSETS TOTAL ASSETS The accompanying notes are an integral part of these statements. 4,076,371 3,263,818 232,055 61,114 176,797 4,546,337 1,280,430 3,265,907 279,422 60,811 150,200 3,754,251 1,072,000 2,682,251 15,781 15,881 $4,161,024 $3,588,045 70 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, CURRENT LIABILITIES: Accounts payable Accrued liabilities Short-term debt Notes payable Long-term debt due within one year Total current liabilities NONCURRENT LIABILITIES: Long-term debt Deferred income taxes Other Total noncurrent liabilities SHAREHOLDERS’ EQUITY: 2009 2008 (in thousands, except share data and per share amounts) $ 70,218 $ 153,851 126,688 105,000 — — 301,906 420,000 681,542 74,567 128,373 — 1,733 25,000 308,957 475,000 479,963 58,651 1,176,109 1,013,614 Common stock, $.10 par value, 160,000,000 shares authorized, 107,057,904 shares issued as of September 30, 2009 and 2008 and 105,486,218 and 105,222,421 shares outstanding as of September 30, 2009 and 2008, respectively 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, 1,571,686 shares in 2009 and 1,835,483 shares in 2008, at cost Total shareholders’ equity 10,706 — 176,039 2,414,942 112,451 2,714,138 31,129 2,683,009 10,706 — 169,497 2,082,518 38,407 2,301,128 35,654 2,265,474 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $4,161,024 $3,588,045 The accompanying notes are an integral part of these statements. 71 Consolidated Statements of Income Years Ended September 30, 2009 2008 2007 OPERATING REVENUES Drilling – U.S. Land Drilling – Offshore Drilling – International Land Other OPERATING COSTS AND EXPENSES Operating costs, excluding depreciation Depreciation Research and development Acquired in-process research and development 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) $1,441,164 $1,542,038 $1,174,956 204,702 237,397 10,775 154,452 328,244 11,809 123,148 320,283 11,271 1,894,038 2,036,543 1,629,658 1,011,558 1,086,666 236,437 210,766 862,254 146,042 9,671 — 59,413 (541) (6,032) 1,833 11,129 57,059 (10,236) (13,490) — — 47,401 (16,661) (41,697) 1,310,506 1,343,727 997,339 583,532 692,816 632,319 4,965 (13,490) — 808 (7,717) 575,815 232,381 10,111 5,038 (18,689) 21,994 (1,230) 7,113 699,929 255,557 17,366 4,234 (10,126) 65,458 (1,532) 58,034 690,353 250,984 9,892 $ 353,545 $ 461,738 $ 449,261 $ $ 3.36 3.32 $ $ 4.43 4.34 $ $ 4.35 4.27 105,364 106,650 104,284 106,424 103,338 105,128 72 Consolidated Statements of Shareholders’ Equity Balance, September 30, 2006 107,058 $10,706 $135,500 $1,215,127 $69,645 3,189 $(49,086) $1,381,892 (in thousands, except per share amounts) Common Stock Shares Amount Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Shares Treasury Stock Amount Total (2,930) 9,170 (298) 4,958 449,261 (2,930) 9,170 6,240 455,501 (18,622) 3,802 682 75,885 3,573 (15,859) 1,792 (15,859) 7,010 (59,987) 1,815,516 (5,048) 449,261 (18,622) 1,645,766 (5,048) 461,738 (30,863) (6,615) (19,938) (1,735) 24,277 56 27,022 — 7,456 (35,654) 2,265,474 (3) 2,082,518 38,407 1,835 353,545 88,519 (14,475) 461,738 (30,863) (6,615) (37,478) 424,260 1,669 (19,938) 14,537 353,545 88,519 (14,475) 74,044 427,589 174 (21,121) 1,272 Comprehensive Income: Net income Other comprehensive income (loss): Unrealized losses on available-for-sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Cash dividends ($.18 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $1.5 million Repurchase of common stock Stock-based compensation Balance, September 30, 2007 Adjustment to initially apply ASC 740-10-30-5 Comprehensive Income: Net income Other comprehensive loss: Unrealized losses on available-for-sale securities, net Amortization of net periodic benefit costs – net of actuarial gain Total other comprehensive loss Total comprehensive income Capital adjustment of equity investee Cash dividends ($.185 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $24.9 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September 30, 2008 Comprehensive Income: Net income Other comprehensive loss: Unrealized gains on available- for-sale securities, net Amortization of net periodic benefit costs – net of actuarial gain Total other comprehensive gain Total comprehensive income Capital adjustment of equity investee Cash dividends ($.20 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $1.2 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September 30, 2009 107,058 10,706 107,058 10,706 (1,156) 1,792 7,010 143,146 1,669 (9,740) 27,022 (56) 7,456 169,497 174 (1,978) 1,273 (1,275) 8,348 The accompanying notes are an integral part of these statements. 73 (21,121) (197) 3,250 (66) 1,273 — 8,348 1,572 $(31,129) $2,683,009 1,275 107,058 $10,706 $176,039 $2,414,942 $112,451 Consolidated Statements of Cash Flows Years Ended September 30, 2009 2008 2007 OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation Provision for (recovery of) 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 Income from asset sales Acquired in-process research and development Deferred income tax expense Other Change in assets and liabilities: Accounts receivable Inventories Prepaid expenses and other Accounts payable Accrued liabilities Deferred income taxes Other noncurrent liabilities Net cash provided by operating activities INVESTING ACTIVITIES: Capital expenditures Acquisition of business, net of cash acquired Proceeds from asset sales Insurance proceeds from involuntary conversion Purchase of short-term investments Proceeds from sale of investments Net cash used in investing activities FINANCING ACTIVITIES: Repurchase of common stock Increase (decrease) in notes payable 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 financing activities Net increase 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. 74 (in thousands) $ 353,545 $ 461,738 $ 449,261 236,437 (645) (16,308) 8,348 — (541) (6,032) — 158,153 2 216,688 (11,625) (12,241) (28,640) (1,261) 6,648 (5,209) 897,319 (880,753) (16) 8,699 541 (12,500) — (884,029) — (1,733) (25,000) 3,840,000 (3,790,000) 2,038 (21,111) 1,272 1,217 6,683 19,973 121,513 210,766 704 (28,009) 7,456 (21,864) (10,236) (13,490) 11,129 117,998 — (127,992) (3,953) (25,602) (15,652) 28,214 11,593 8,028 610,828 (705,635) (12,041) 22,908 13,926 — 25,507 (655,335) — 1,733 — 3,550,000 (3,495,000) — (19,333) 14,537 24,868 76,805 32,298 89,215 146,042 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 4,235 561,067 (894,214) — 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 $ 141,486 $ 121,513 $ 89,215 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. and its wholly-owned subsidiaries. Fiscal years of our foreign operations end on August 31 to facilitate reporting of consolidated results. There were no significant intervening events which materially affected the financial statements. FOREIGN CURRENCIES The functional currency for all our 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 and foreign currency translations into U.S. dollars are included in direct operating costs. Aggregate foreign currency remeasurement and transaction losses included in direct operating costs totaled $2.9 million and $1.6 million in fiscal 2009 and 2008, respectively, and gains of $1.0 million in fiscal 2007. USE OF ESTIMATES The preparation of our 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. RECENTLY ADOPTED ACCOUNTING STANDARD In June 2009, the Financial Accounting Standards Board (‘‘FASB’’) issued Statement of Financial Accounting Standard (‘‘SFAS’’) No. 168, The FASB Accounting Standards Codification(cid:2) and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162 (‘‘SFAS 168’’). SFAS 168 replaced all previously issued accounting standards and establishes the FASB Accounting Standards Codification(cid:2) (‘‘ASC’’) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with U.S. GAAP. The new standard, ASC 105-10, was effective for all interim and annual periods ending after September 15, 2009. The ASC is not intended to change existing U.S. GAAP. The adoption of this pronouncement only resulted in changes to our financial statement disclosure references. As such, adoption of this pronouncement had no effect on our consolidated financial position, results of operations, or cash flows. All references to U.S. GAAP within this report on Form 10-K are updated to reflect the new codification. CASH AND CASH EQUIVALENTS Cash equivalents consist of investments in short-term, highly liquid securities having original maturities of three months or less. The carrying values of these assets approximate their fair values. We primarily utilize a cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts for moving funds to, and several ‘‘zero-balance’’ disbursement accounts for funding 75 payroll and accounts payable. As a result of our 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 are included in accounts payable where applicable and included as a financing activity in the Consolidated Statements of Cash Flows. RESTRICTED CASH AND CASH EQUIVALENTS We had restricted cash and cash equivalents of $13.9 million and $13.3 million at September 30, 2009 and 2008, respectively. Restricted cash is primarily for the purpose of potential insurance claims in our wholly- owned captive insurance company. Of the total at September 30, 2009, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $10.9 million. The remaining restricted cash consists of $1.0 million held in escrow in conjunction with the 2008 acquisition of TerraVici Drilling Solutions. 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 2009 $11,890 $ 2,000 2008 $10,274 $ 3,012 INVENTORIES AND SUPPLIES Inventories and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventories and supplies are valued at the lower of cost (moving average or actual) or market value. INVESTMENTS We maintain 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. We regularly review investment securities for impairment based on criteria that include the extent to which the investment’s carrying value exceeds its related fair 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 by recognizing our proportionate share of the income or loss of the investee. Effective April 1, 2009, Atwood Oceanics, Inc. (Atwood) was accounted for as an available-for-sale investment, as we determined that we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes deferred as a component of other comprehensive income. We have no other equity method investments. 76 DERIVATIVE FINANCIAL INSTRUMENTS We are exposed to market risk in the normal course of business operations due to ongoing investing and financing activities. The risk of loss can be assessed from the perspective of adverse changes in fair values, cash flows and future earnings. ASC 815, Derivatives and Hedging, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. We have not historically entered into derivative financial instruments for trading purposes or for speculation. During fiscal 2009, we adopted the disclosure provisions contained in ASC 815 that provides companies with requirements for enhanced disclosures about derivative instruments and hedging activities to enable investors to better understand their effects on a company’s financial position, financial performance and cash flows. For further information regarding the derivative instruments including our disclosures of our interest rate swap, refer to Note 2, Debt, and Note 7, Financial Instruments and Fair Value Measurement, of these Consolidated Financial Statements. 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, 10-45 years; and other, 2-23 years). Depreciation in the Consolidated Statements of Income includes abandonments of $5.3 million, $13.3 million and $4.1 million for fiscal 2009, 2008 and 2007, respectively. The cost of maintenance and repairs is charged to direct operating cost, while betterments and refurbishments are capitalized. We lease office space and equipment for use in operations. Leases are evaluated at inception or at any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases as appropriate under ASC 840, Leases. We do not have significant capital leases. CAPITALIZATION OF INTEREST We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal 2009, 2008 and 2007 was $6.6 million, $4.7 million, and $9.4 million, respectively. VALUATION OF LONG-LIVED ASSETS We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with ASC 360-10. Changes that could prompt such an assessment 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 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 77 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. ACQUISITIONS We account for acquired businesses using the purchase method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to acquired in-process research and development are expensed at the date of acquisition. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact results of operations. Accordingly, for significant items, assistance from third party valuation specialists is typically obtained. The valuations are based on information available near the acquisition date and are based on expectations and assumptions that have been deemed reasonable by management. SELF INSURANCE ACCRUALS We have accrued a liability for estimated worker’s compensation and other casualty claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material. DRILLING REVENUES Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive 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 for out-of-pocket expenses are recorded as revenues and direct costs. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. RENT REVENUES We enter into leases with tenants in our 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 in other operating revenues in the Consolidated Statements of Income. Our rent revenues are as follows: Years Ended September 30, Minimum rents Overage and percentage rents 2009 $8,803 $1,414 2008 (in thousands) $9,469 $1,582 2007 $8,873 $1,474 78 At September 30, 2009, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2010 2011 2012 2013 2014 Thereafter Total Amount $ 7,751 6,206 4,491 3,151 2,166 3,721 $27,486 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2009 and 2008, the cost and accumulated depreciation for real estate properties were as follows (in thousands): September 30, Real estate properties Accumulated depreciation 2009 2008 $61,114 (37,786) $23,328 $60,811 (36,155) $24,656 INCOME TAXES Current income tax expense is the amount of income taxes expected to be payable for the current year. 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 our assets and liabilities. We provide for uncertain tax positions when such tax positions do not meet the recognition thresholds or measurement standards prescribed in ASC 740-10-30-5, Deferred Tax Expense (or Benefit), which was adopted effective October 1, 2007, and is more fully discussed in Note 3. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. We recognize accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidation Statements of Income. On October 1, 2009, we adopted the requirements regarding the accounting for income tax benefits of dividends on share-based payment awards. As a result of the adoption, we recognize a realized income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share- based payment awards that is charged to retained earnings as an increase to additional paid-in capital. The adoption did not have a material impact on our financial position, results of operations or cash flows. 79 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 We record compensation expense associated with stock options in accordance with ASC 718, Compensation—Stock Compensation. Compensation expense is determined using a fair-value-based measurement method for all awards granted. In computing the impact, the fair value of each option is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing certain assumptions for a risk free interest rate, volatility, dividend yield and expected remaining term of the awards. The assumptions used in calculating the fair value of share-based payment awards represent management’s best estimates, but these estimates involve inherent uncertainties and the application of management judgment. Stock-based compensation is recognized on a straight-line basis over the requisite service periods of the stock awards, which is generally the vesting period. Compensation expense related to stock options is recorded as a component of general and administrative expenses in the Consolidated Statements of Income. 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 June 2008, the FASB issued guidance contained in ASC 260-10-45 to clarify that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method pursuant to ASC 260-10-05, Earnings per Share. We will adopt ASC 260-10-45 on October 1, 2009. All prior-period earnings per share data presented will be adjusted retrospectively to conform to the provisions of ASC 260-10-45. We expect the impact, if any, of adopting ASC 260-10-45 to be immaterial on our prior period earnings per share. ASC 820-10-65, Transition related to FASB Staff Position FAS157-2, delays the effective date for the disclosure requirements included in ASC 820-10 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually). ASC 820-10-65 will be adopted on October 1, 2009 and is not expected to have a material impact on our Consolidated Financial Statements. ASC 715-20-65, Transition related to SFAS 132R-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. The new guidance requires employers of public and nonpublic companies to disclose more information about how investment allocation decisions are made, more information about major categories of plan assets, including concentration of risk and fair-value measurements, and the fair-value techniques and inputs used to measure plan assets. The disclosure requirements are effective for years ending after December 15, 2009. The disclosure requirements will be 80 adopted for the year ended September 30, 2010, on a prospective basis. We do not expect the adoption to have a material impact on the Consolidated Financial Statements. In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (ASU 2009-05). This update provides amendments to ASC 820, Fair Value Measurements and Disclosure, for the fair value measurement of liabilities when a quoted price in an active market is not available. ASU 2009-05 is effective for reporting periods beginning after August 28, 2009, which means that it will be effective for our first quarter beginning October 1, 2009. We do not currently believe this update will have a material impact on the Consolidated Financial Statements. NOTE 2 DEBT At September 30, 2009 and 2008, we had $420 million and $475 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table (in thousands): Unsecured intermediate debt issued August 15, 2002: Series B, due August 15, 2009, 5.91% Series C, due August 15, 2012, 6.46% Series D, due August 15, 2014, 6.56% Unsecured senior notes issued July 21, 2009: Due July 21, 2012, 6.10% Due July 21, 2013, 6.10% Due July 21, 2014, 6.10% Due July 21, 2015, 6.10% Due July 21, 2016, 6.10% Unsecured senior credit facility due December 18, 2011, .60% Less long-term debt due within one year Long-term debt September 30, 2009 2008 $ — 75,000 75,000 40,000 40,000 40,000 40,000 40,000 70,000 $420,000 — $420,000 $ 25,000 75,000 75,000 — — — — — 325,000 $500,000 25,000 $475,000 The intermediate unsecured debt outstanding at September 30, 2009 matures over a period from August 2012 to August 2014 and carries a weighted-average interest rate of 6.5 percent, which is paid semi-annually. The terms require that we maintain a minimum ratio of debt to total capitalization. The debt is held by various entities, including $3 million held by a company affiliated with one of our Board members. On July 21, 2009, we closed a private placement of senior unsecured fixed-rate notes that will mature July 2016 and received proceeds of $200 million. Interest on the notes will be paid semi-annually based on an annual rate of 6.10 percent. We will make five equal annual principal repayments of $40 million starting on the third anniversary of the closing date. Financial covenants require that we maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and 81 customary in unsecured debt arrangements for companies that are similar in size and credit quality. The $200 million of proceeds from this facility were used to reduce borrowings under the $400 million senior credit facility by $105 million and the remainder was used to fund capital expenditures and for other general corporate purposes. We have an agreement with a multi-bank syndicate for a $400 million senior unsecured credit facility maturing December 2011. While we have the option to borrow at the prime rate for maturities of less than 30 days, we anticipate 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). We pay 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 our total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. At September 30, 2009, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. At September 30, 2009, we had two letters of credit totaling $21.9 million under the facility and had $70 million borrowed against the facility with $308.1 million available to borrow. The advances bear an interest rate of 0.60 percent at September 30, 2009. Subsequent to September 30, 2009, the debt was reduced by $30 million and we had $338.1 million available to borrow. We have an agreement with a multi-bank syndicate for a $105 million unsecured line of credit that will mature January 2010. We closed on the agreement on January 21, 2009. We committed to fully fund this facility for the entire term at a spread over 30 day LIBOR. The spread over LIBOR is determined according to the same scale of debt to total capitalization used in our $400 million facility which is described in the preceding paragraph. The spread over LIBOR for the new facility has increased to a range of 2 percent to 2.75 percent. At September 30, 2009, the spread on the borrowing was 2.25 percent over LIBOR. Simultaneous with the closing of this facility, we entered into an interest-rate swap with the same maturity and a notional amount of $105 million. We believe that the swap will act to fix the annualized interest rate of the facility at approximately 3.17 percent assuming the spread remains at 2.25 percent over LIBOR. The interest rate swap qualifies as a derivative and was not designated as a hedging instrument and, as such, we have not applied hedge accounting. At the end of an accounting period, the interest rate swap is recorded in the Consolidated Balance Sheet at fair value, either in other current assets or accrued liabilities, and any related gains or losses are recognized on our Consolidated Statement of Income within interest expense. The fair value of the interest rate swap liability at September 30, 2009 was $0.2 million and is included in accrued liabilities in the Consolidated Balance Sheet. Interest expense on the interest rate swap was $0.6 million during fiscal year 2009. Financial covenants in both facilities require that we 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. Both facilities contain additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2009, we were in compliance with all debt covenants. Additionally, as of September 30, 2009, we had unsecured letters of credit totaling $3.2 million which were used to obtain surety bonds for international operations. 82 At September 30, 2009, aggregate maturities of long-term debt are as follows (in thousands): Years ending September 30, 2010 2011 2012 2013 2014 Thereafter NOTE 3 INCOME TAXES The components of the provision for income taxes are as follows: Years Ended September 30, 2009 Current: Federal Foreign State Deferred: Federal Foreign State Total provision $ 45,780 19,559 8,889 74,228 148,367 1,279 8,507 158,153 $232,381 $ — — 185,000 40,000 115,000 80,000 $420,000 2007 $125,169 31,552 11,969 168,690 74,389 1,528 6,377 82,294 $250,984 2008 (in thousands) $ 97,871 28,875 10,813 137,559 110,077 (1,467) 9,388 117,998 $255,557 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 2009 $571,028 4,787 $575,815 2008 (in thousands) $627,344 72,585 $699,929 2007 $579,589 110,764 $690,353 Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management’s judgments using certain estimates and assumptions that we 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 may be recorded against the deferred tax assets resulting in additional income tax expense in the future. 83 The components of our 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 2009 2008 (in thousands) $597,647 123,763 — (108) 721,302 12,901 3,740 48,107 32,042 3,939 100,729 48,107 52,622 $668,680 $440,081 26,029 37,079 557 503,746 4,187 4,509 43,495 32,901 4,124 89,216 43,495 45,721 $458,025 The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2009, we had state and foreign net operating loss carryforwards for income tax purposes of $1.0 million and $13.8 million, respectively, and foreign tax credit carryforwards of approximately $43.3 million which will expire in years 2010 through 2018. The valuation allowance is primarily attributable to state and foreign net operating loss carryforwards and foreign tax credit carryforwards which more likely than not 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, 2009 2008 2007 U.S. Federal income tax rate Effect of foreign taxes State income taxes Effective income tax rate 35% 3 2 40% 35% — 2 37% 35% (1) 2 36% Effective October 1, 2007, we adopted ASC 740-10-30-5, Deferred Tax Expense (or Benefit), issued by the FASB in July 2006. The guidance clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with ASC 740, Income Taxes, and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a tax return. Under ASC 740-10-30-5, the impact of an uncertain income tax position must be 84 recognized in the financial statements at the largest amount that is more likely than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has less than a 50 percent likelihood of being sustained. Additionally, guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition was provided in ASC 740-10-30-5. The cumulative effect of adoption resulted in a decrease of approximately $5.0 million in retained earnings. We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in other expense in the Consolidated Statements of Income. As of September 30, 2009 and 2008, we had accrued interest and penalties of $1.7 million and $2.5 million, respectively. A reconciliation of the change in our gross unrecognized tax benefits for the fiscal year ended September 30, 2009 and 2008 is as follows (in thousands): September 30, Unrecognized tax benefits at October 1, Gross decreases – tax positions in prior periods Gross increases – current period effect of tax positions Unrecognized tax benefits at September 30 2009 $5,692 (731) 283 $5,244 2008 $4,628 — 1,064 $5,692 As of September 30, 2009 and September 30, 2008, our liability for unrecognized tax benefits was $5.2 million and $5.7 million, respectively, which would affect the effective tax rate if recognized. The decrease in unrecognized tax benefits was mainly due to an effective settlement with the Argentinean tax authorities. The increase in unrecognized tax benefits was mainly due to the current period impact of tax positions taken in prior periods. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets. We file a consolidated U.S. federal income tax return, as well as income tax returns in various states and foreign jurisdictions. The tax years that remain open to examination by U.S. federal and state jurisdictions include fiscal years 2005 through 2008. Audits in foreign jurisdictions are generally complete through fiscal year 2001. It is reasonably possible that the amount of the unrecognized tax benefits with respect to certain unrecognized tax positions will increase or decrease during the next 12 months. However, we do not expect the change to have a material effect on results of operations or financial position. NOTE 4 SHAREHOLDERS’ EQUITY On September 30, 2009, we had 105,486,218 outstanding common stock purchase rights (‘‘Rights’’) pursuant to the terms of the Rights Agreement dated January 8, 1996, as amended by Amendment No. 1 dated December 8, 2005. As adjusted for the two-for-one stock splits in fiscals 1998 and 2006, and as long as the Rights are not separately transferable, one-half Right attaches to each share of our common stock. Under the terms of the Rights Agreement each Right entitles the holder thereof to purchase one full unit consisting of 85 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 we are acquired in a merger or certain other business combination transactions (including one in which we are the surviving corporation), or more than 50 percent of our 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 We have one plan providing for common-stock based awards to employees and to non-employee Directors. The plan permits the granting of various types of awards including stock options and restricted stock awards. 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 the grant date. We have the right to satisfy option exercises from treasury shares and from authorized but unissued shares. A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal 2009, 2008 and 2007 is as follows (in thousands): September 30, Compensation expense Stock options Restricted stock 2009 2008 2007 $6,899 1,449 $8,348 $6,210 1,246 $7,456 $5,643 1,367 $7,010 Benefits of tax deductions in excess of recognized compensation cost of $1.2 million, $24.9 million and $1.5 million are reported as a financing cash flow in the Consolidated Statements of Cash Flows for fiscal 2009, 2008 and 2007, respectively. STOCK OPTIONS Vesting requirements for stock options are determined by the Human Resources Committee of our Board of Directors. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years. We use the Black-Scholes formula to estimate the fair value of stock options granted to employees. 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 weighted-average fair value 86 calculations for options granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below. Options that were granted in prior periods are based on assumptions prevailing at the date of grant. Risk-free interest rate Expected stock volatility Dividend yield Expected term (in years) 2009 1.7% 43.3% 0.9% 5.8 2008 3.3% 31.1% 0.5% 4.8 2007 4.6% 35.9% 0.7% 5.5 Risk-Free Interest Rate. The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option. Expected Volatility Rate. Expected volatilities are based on the daily closing price of our 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 our current dividend yield. Expected Term. The expected term of the options granted represents the period of time that they are expected to be outstanding. We estimate the expected term of options granted based on historical experience with grants and exercises. Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $8.16, $10.81 and $10.36 per share for fiscal 2009, 2008 and 2007, respectively. The following summary reflects the stock option activity for our common stock and related information for fiscal 2009, 2008 and 2007 (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2009 2008 2007 Weighted-Average Exercise Price $20.02 21.07 12.18 26.91 $20.55 $17.42 Options 4,819 865 (267) (16) 5,401 3,599 1,656 Weighted-Average Exercise Price $15.80 35.11 11.87 27.31 $20.02 $15.07 Options 6,032 742 (1,845) (110) 4,819 3,206 2,511 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 3,231 87 The following table summarizes information about stock options at September 30, 2009 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $9.4178 to $13.870 $16.0100 to $21.065 $26.8950 to $35.105 $9.4178 to $35.105 Options 1,972 1,583 1,846 5,401 Weighted-Average Remaining Life Weighted-Average Exercise Price 2.6 7.3 7.3 5.6 $12.25 $18.75 $30.97 $20.55 Options 1,972 753 874 3,599 Weighted-Average Exercise Price $12.25 $16.20 $30.11 $17.42 At September 30, 2009, the weighted-average remaining life of exercisable stock options was 4.2 years and the aggregate intrinsic value was $79.6 million with a weighted-average exercise price of $17.42 per share. The number of options vested or expected to vest at September 30, 2009 was 5,359,244 with an aggregate intrinsic value of $102.0 million and a weighted-average exercise price of $20.50 per share. As of September 30, 2009, the unrecognized compensation cost related to the stock options was $11.4 million. That cost is expected to be recognized over a weighted-average period of 2.4 years. The total intrinsic value of options exercised during fiscal 2009, 2008 and 2007 was $4.9 million, $21.9, and $5.8 million, respectively. The grant date fair value of shares vested during fiscal 2009, 2008 and 2007 was $6.3 million, $5.8 million and $5.4 million, respectively. RESTRICTED STOCK Restricted stock awards consist of our common stock and are time vested over three to five years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards is determined based on the closing price of our shares on the grant date. As of September 30, 2009, there was $2.2 million of total unrecognized compensation cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 1.5 years. 88 A summary of the status of our restricted stock awards as of September 30, 2009, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2009, 2008 and 2007 is as follows (share amounts in thousands): Outstanding at October 1, Granted Vested Forfeited/Expired Outstanding on September 30, 2009 Weighted-Average Grant Date Fair Value per Share $29.92 — 29.52 — $30.06 Shares 243 — (66) — 177 2008 Weighted-Average Grant Date Fair Value per Share $29.27 35.11 16.01 30.24 2007 Weighted-Average Grant Date Fair Value per Share $29.57 26.90 — — Shares 213 27 — — $29.92 240 $29.27 Shares 240 22 (3) (16) 243 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: September 30, Basic weighted-average shares Effect of dilutive shares: Stock options and restricted stock Diluted weighted-average shares 2009 105,364 1,286 106,650 2008 (in thousands) 104,284 2,140 106,424 2007 103,338 1,790 105,128 The following shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings per share because their inclusion would have been anti-dilutive: Shares excluded from calculation of diluted earnings per share Weighted-average price per share 2009 2008 2007 (in thousands, except per share amounts) 1,206 $33.12 — $ — 594 $30.24 NOTE 7 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT The estimated fair value of our available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of 89 accounting at September 30, 2008 (see Note 1), investments in limited partnerships carried at cost and assets held in a Non-qualified Supplemental Savings Plan: Equity Securities: September 30, 2009 September 30, 2008 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $129,183 $ 7,685 $210,640 $ 67,867 $— $— $339,823 $ 75,552 On an on-going basis, we evaluate the marketable equity securities to determine if a decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis established. We review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. During the years ended September 30, 2008 and 2007, marketable equity available-for-sale securities with a fair value at the date of sale of $25.5 million and $73.4 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $22.0 million and $65.5 million, respectively. We had no sales of marketable equity available-for-sale securities in fiscal 2009. The investments in the limited partnerships carried at cost were approximately $12.4 million at September 30, 2009 and 2008. The estimated fair value of the limited partnerships was $19.7 million and $17.3 million at September 30, 2009 and 2008, respectively. The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $4.2 million and $6.4 million at September 30, 2009 and 2008, respectively. The majority of cash equivalents are invested in taxable and non-taxable money-market mutual funds. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments. At September 30, 2009, our short-term investments consisted of a bank certificate of deposit with an original maturity greater than three months. Interest earned is included in interest and dividend income on the Consolidated Statements of Income. The carrying amount of the certificate of deposit approximates fair value. During fiscal 2007, we liquidated our position in auction rate securities with no realized gains or losses. The proceeds of $48.3 million were included in the sale of investments under investing activities on the Consolidated Statements of Cash Flows. There were no purchases or sales of auction rate securities during fiscal 2009 and 2008. 90 The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2009 and 2008. During fiscal 2009, we adopted the disclosure requirements of ASC 820-10, Fair Value Measurements and Disclosures, issued by the FASB in September 2006, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements required under other accounting pronouncements, but does not change existing guidance for carrying instruments at fair value. ASC 820-10-65, issued in February 2008, allows a delayed application of ASC 820-10 for nonfinancial assets and liabilities until the first quarter of fiscal 2010. The FASB defines fair value as ‘‘the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date’’. Our adoption of the required portions of ASC 820-10 as of October 1, 2008 did not have a material impact on our financial position, results of operations and cash flows. ASC 820-10 establishes a fair value hierarchy to prioritize the inputs used in valuation techniques into three levels as follows: (cid:129) Level 1 – Observable inputs that reflect quoted prices in active markets for identical assets or liabilities in active markets. (cid:129) Level 2 – Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. (cid:129) Level 3 – Valuations based on inputs that are unobservable and not corroborated by market data. At September 30, 2009, our financial assets utilizing Level 1 inputs include cash and cash equivalents, money market funds we have elected to classify as restricted assets and equity securities with active markets. For these items, quoted current market prices are readily available. During fiscal 2009, we entered into an interest rate swap agreement with a $105 million notional amount to hedge the risk of changes in the interest rate associated with amounts outstanding under an unsecured line of credit that expires in January 2010. The fair value of the swap agreement was determined using Level 2 inputs. Level 2 inputs also include a bank certificate of deposit classified as a short-term investment and restricted cash included in current assets. Currently, we do not have any financial instruments utilizing Level 3 inputs. 91 The following table summarizes our assets and liabilities measured at fair value on a recurring basis presented in our Consolidated Balance Sheets as of September 30, 2009: Total Measured at Fair Value Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Cash and cash equivalents Short-term investments Investments Other current assets Other assets $141,486 $141,486 12,500 339,823 11,890 2,000 — 339,823 10,866 2,000 $ — 12,500 — 1,024 — Total assets measured at fair value $507,699 $494,175 $13,524 Liabilities: Accrued liabilities – interest rate swap Total liabilities measured at fair value $ $ 229 229 $ $ — — $ $ 229 229 $— — — — — $— $— $— The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2009 and September 30, 2008. September 30, Carrying value of long-term fixed-rate debt Fair value of long-term fixed-rate debt 2009 2008 (in thousands) $350.0 $380.9 $175.0 $198.0 The fair value for fixed-rate debt was estimated using discounted cash flows and interest rates currently being offered on credits with similar maturities and credit profiles. The outstanding line of credit and short-term debt bear interest at market rates and the cost of borrowings, if any, would approximate fair value. ASC 825-10, Financial Instruments, permits choosing to measure certain financial assets and liabilities at fair value. We elected not to measure any assets or liabilities at fair value which were not being so measured prior to adopting ASC 820-10. Therefore, our adoption of ASC 820-10 as of October 1, 2008 did not have an impact on our financial position, results of operations or cash flows. 92 NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of other comprehensive income for the years ended September 30, 2009, 2008 and 2007 were as follows (in thousands): Years Ended September 30, 2009 2008 2007 Unrealized appreciation (depreciation) on securities, net of tax of $54,254, $(10,558) and $23,076 $ 88,519 $(17,227) $ 37,654 Reclassification of realized gains in net income, net of tax of $0, $8,358 and $24,874 Minimum pension liability adjustments, net of tax of $5,621 Amortization of net periodic benefit costs – net of actuarial gain, net of tax of $(8,872) and $(4,054) — — (14,475) $ 74,044 (13,636) — (6,615) $(37,478) (40,584) 9,170 — $ 6,240 The components of accumulated other comprehensive income (loss) at September 30, 2009 and 2008, net of applicable tax effects, were as follows (in thousands): September 30, Unrealized appreciation on securities Unrecognized actuarial gain (loss) and prior service cost 2009 $130,597 (18,146) $112,451 2008 $42,078 (3,671) $38,407 NOTE 9 ACQUISITION OF TERRAVICI DRILLING SOLUTIONS On May 21, 2008, we acquired a private limited partnership, TerraVici Drilling Solutions (TerraVici) in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets acquired and liabilities assumed of TerraVici are recorded as of the acquisition date, at their respective fair values, and included in our consolidated financial statements from the date of acquisition. TerraVici is included with all other non-reportable business segments. TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with the FlexRig. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer. The acquisition was accounted for using the purchase method of accounting. The purchase price was allocated to identifiable assets acquired and liabilities assumed based upon their estimated fair values, with the excess purchase price recorded as goodwill, none of which is tax deductible. 93 The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands): Current assets Fixed assets Trademark In-process research and development Other noncurrent assets Assets acquired Liabilities assumed Net assets acquired Goodwill Acquisition cost $ 371 4,257 919 11,129 280 16,956 (5,477) 11,479 702 $12,181 In-process research and development, or IPR&D, represents rotary steerable system (RSS) tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. Accordingly, the purchase price allocated to IPR&D was expensed immediately subsequent to the acquisition. This charge will be amortized over 15 years for tax purposes. The $11.1 million estimated fair value of IPR&D was derived using the multi-period excess-earnings method. NOTE 10 EMPLOYEE BENEFIT PLANS We maintain a domestic noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, we 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, we adopted the provisions of ASC 715, ‘‘Compensation—Retirement Benefits’’. 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 we have 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. 94 The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 2009 and a statement of the funded status as of September 30, 2009 and 2008 (in thousands): Accumulated Benefit Obligation (‘‘ABO’’) Changes in Projected Benefit Obligations (‘‘PBO’’) Projected benefit obligation at beginning of year Interest cost Actuarial gain (loss) 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 at end of year 2009 $ 89,996 $ 69,475 4,988 18,977 (3,444) $ 89,996 $ 59,605 270 750 (3,444) $ 57,181 $(32,815) 2008 $ 69,475 $ 78,247 4,919 (8,975) (4,716) $ 69,475 $ 74,877 (13,662) 3,106 (4,716) $ 59,605 $ (9,870) September 30, Amounts Recognized in the Consolidated Balance Sheets (in thousands): 2009 2008 Accrued liabilities Noncurrent liabilities-other Net amount recognized The amounts recognized in Accumulated Other Comprehensive Income at September 30, 2009 and 2008, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial gain (loss) Prior service cost Total $ (40) (32,775) $(32,815) $(29,267) (1) $(29,268) $ (43) (9,827) $(9,870) $(5,919) (1) $(5,920) 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 loss of $2.1 million. 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 2009 7.25% 5.42% 8.00% 2008 6.25% 7.25% 8.00% 2007 5.75% 6.25% 8.00% We contributed $0.8 million to the Pension Plan in fiscal 2009 to fund distributions in lieu of liquidating pension assets. We estimate contributing at least $3.0 million in fiscal 2010 to meet the minimum contribution required by law and expect to make additional contributions to continue funding distributions. Subsequent to 95 September 30, 2009, we contributed $1.0 million to the plan. With the unpredictability in the equity, debt and global markets, it is possible that contributions in fiscal 2010 will be greater than expected. Components of the net periodic pension expense (benefit) were as follows (in thousands): Years Ended September 30, Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Net pension expense (benefit) 2009 $ 4,988 (4,643) (1) 3 2008 $ 4,919 (5,990) — 9 2007 $ 4,865 (5,123) — 139 $ 347 $(1,062) $ (119) 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). 2010 $3,789 2011 $3,977 2012 $4,439 2013 $4,824 2014 $5,041 2015-2019 $28,492 Total $50,562 Years Ended September 30, Included in the Pension Plan is an unfunded supplemental executive retirement plan. INVESTMENT STRATEGY AND ASSET ALLOCATION Our 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. We maintain 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, our financial strength and ability to fund potential shortfalls are considered. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the Plans’ investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes. The target allocation for 2010 and the asset allocation for the Pension Plan at the end of fiscal 2009 and 2008, by asset category, follows: Target Allocation Percentage of Plan Assets At September 30, Asset Category U.S. equities International equities Fixed income Real estate and other Total 2009 57% 15 27 1 100% 2008 58% 15 24 3 100% 2010 56% 14 25 5 100% 96 DEFINED CONTRIBUTION PLAN Substantially all employees on the United States payroll may elect to participate in the 401(k)/Thrift Plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first five percent of the participant’s compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was $14.3 million, $15.0 million, and $10.9 million in fiscal 2009, 2008 and 2007, respectively. FOREIGN PLAN We maintain an unfunded pension plan in one of our international subsidiaries. Pension expense was approximately $0.4 million, $0.4 million and $0.3 million in fiscal 2009, 2008 and 2007, respectively. The pension liability at September 30, 2009 and 2008 was $5.0 million. NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for 2009, 2008 and 2007: September 30, Reserve for bad debt: Balance at October 1, Provision for (recovery of) bad debt Write-off of bad debt Balance at September 30, 2009 $1,331 (645) (27) $ 659 2008 (in thousands) $ 2,957 704 (2,330) $ 1,331 2007 $2,007 1,030 (80) $2,957 97 Accounts receivable, prepaid expenses, accrued liabilities, and long-term liabilities at September 30 consist of the following: September 30, Accounts receivable, net of reserve: Trade receivables Income tax Prepaid expenses and other: Prepaid value added tax Restricted cash Prepaid insurance Deferred mobilization Other Accrued liabilities: 2009 2008 (in thousands) $246,790 — $246,790 $ 25,979 11,890 8,304 9,046 8,330 $446,846 15,987 $462,833 $ 6,146 10,274 9,957 13,853 11,034 $ 63,549 $ 51,264 Taxes payable, other than income tax $ 49,613 $ 42,884 Accrued income taxes Self-insurance liabilities Payroll and employee benefits Accrued operating costs Deferred income Other Noncurrent liabilities: 15,992 2,626 13,827 2,150 16,514 25,966 $126,688 — 3,696 44,525 16,500 55 20,713 $128,373 Pension and other non-qualified retirement plans $ 42,422 $ 21,533 Deferred income Uncertain tax positions including interest and penalties Self-insurance liabilities Deferred mobilization Other NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, Cash payments: Interest paid, net of amounts capitalized Income taxes paid 2009 $12,097 $39,415 98 7,024 6,298 6,103 5,164 7,556 839 8,163 6,557 12,000 9,559 $ 74,567 $ 58,651 2008 (in thousands) $ 18,595 $133,194 2007 $ 9,713 $181,591 Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2009, 2008 and 2007, does not include additions which have been incurred but not paid for as of the end of the year. The following table reconciles total capital expenditures incurred to total capital expenditures in the Consolidated Statements of Cash Flows: September 30, Capital expenditures incurred Additions incurred prior year but paid for in current year Additions incurred but not paid for as of the end of the year Capital expenditures per Consolidated Statements of Cash 2009 $823,712 66,857 2008 (in thousands) $745,538 26,954 2007 $825,448 95,720 (9,816) (66,857) (26,954) Flows $880,753 $705,635 $894,214 NOTE 13 RISK FACTORS CONCENTRATION OF CREDIT Financial instruments which potentially subject us to concentrations of credit risk consist primarily of temporary cash investments, short-term investments and trade receivables. We place temporary cash investments in the U.S. with established financial institutions and invest in a diversified portfolio of highly rated, short-term money market instruments. In Venezuela, we had $45.3 million in cash at September 30, 2009, as discussed below, along with other considerations in Note 14, Operations and Risks in Venezuela. Our 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 our international sales, however, are to large international or government- owned national oil companies. We perform ongoing credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide 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 in recent history. VOLATILITY OF MARKET Our operations can be materially affected by oil and gas prices. Oil and natural gas prices are volatile and have declined substantially from the peak levels in June 2008. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining a customer’s future spending levels. This volatility, along with the difficulty in predicting future prices can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The deterioration in the credit and capital markets during the past year could cause difficulty for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction 99 in customer spending and the demand for drilling services. This reduction in spending could have a material adverse effect on our operations. SELF-INSURANCE We self-insure a significant portion of expected losses relating to worker’s compensation, general, and automobile liability. 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. We maintain certain other insurance coverage with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We record 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 we believe 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. We have a wholly-owned captive insurance company, White Eagle Assurance Company (White Eagle), which provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles. With the exception of ‘‘named wind storm’’ risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1.0 million per occurrence deductible, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering six offshore platform rigs for ‘‘named wind storm’’ risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers two rigs and has a $40 million limit and a $3.5 million deductible. Rig property insurance coverage expires in May 2010. No insurance is carried against loss of earnings or business interruption. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, we are generally entitled to indemnification under our drilling contracts from this risk. 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. INTERNATIONAL DRILLING OPERATIONS International drilling operations are a significant contributor to our revenues and net operating income. There can be no assurance that we will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on our financial position, results of operations, and cash flows. Also, the success of our 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. Additionally, in the event that extended labor strikes occur or a country experiences significant political, economic or social instability, we could experience shortages in labor and/or material and supplies necessary to operate some of our drilling rigs, thereby causing an adverse effect on our business, financial condition and results of operations. 100 We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period. The economy in Venezuela has not been considered to be highly inflationary in the past four years. We have completed an analysis to determine if Venezuela should be accounted for as a highly inflationary economy under the provisions of ASC 830 during the current fiscal year. Based on current Securities and Exchange Commission guidance, we used two relevant inflation indexes for this analysis; the Consumer Price Index (CPI) and the National Consumer Price Index (NCPI). These indexes are published by the Central Bank of Venezuela and they are acceptable for calculation of the three year cumulative inflation rate. Using a blended NCPI and CPI rate for the three year period ended June 30, 2009, Venezuela would not be considered highly inflationary as the cumulative inflation rate is less than 100 percent. All of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements. NOTE 14 OPERATIONS AND RISKS IN VENEZUELA Typically, contract drilling revenues are recognized as services are performed. In U.S. generally accepted accounting principles, one of the basic revenue recognition criteria is that collectability of the revenue is reasonably assured. Our revenue in Venezuela is from providing drilling services to Petroleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company. We determined, as of the beginning of the second quarter of fiscal 2009 and forward, that the revenue recognition criteria in Venezuela is no longer met as collectability of revenue is not reasonably assured, primarily due to the uncertainty of the timing of collectability as discussed further below. As a result, $57.9 million of revenue was not recorded in the International Land segment during fiscal 2009. Revenue not recognized in 2009 will be recognized in future periods when cash is collected. Since the beginning of the second quarter of fiscal 2009, approximately $69.3 million (U.S. dollars and U.S. currency equivalent) was collected from PDVSA of which $61.4 million was applicable to accounts receivable at the end of the first quarter of fiscal 2009. As of September 30, 2009, the Consolidated Balance Sheets include accounts receivable from PDVSA of $26.6 million. Subsequent to the end of fiscal 2009, additional payments of approximately $20.8 million (U.S. dollars and U.S. currency equivalent) were received through November 24, 2009. Approximately 73 percent of this corresponds to accounts receivable at the end of the first quarter of fiscal 2009 and the remainder to invoices issued for work performed after the first quarter of fiscal 2009. We do not have enough information to conclude that the remaining receivable balance is not probable of collection. However, there continues to be uncertainty regarding the timing of the collection due to the current political, economic and social instability in Venezuela, the dependence by Venezuela on oil to largely support its economy and the failure of PDVSA to pay many service companies working in Venezuela. The collection of receivables from PDVSA has historically been more difficult and slower than that of other customers in international countries in which we have drilling operations due to PDVSA policies and procedures. During the second quarter of fiscal 2009, we began discontinuing work for PDVSA as contracts expired. All of our eleven rigs were active in Venezuela during the first quarter of fiscal 2009. At the end of fiscal 2009, one rig remained active and has since become idle. At September 30, 2009, the net book value of long-lived assets in Venezuela was $71.6 million. We will continue to pursue future drilling opportunities in Venezuela, but 101 do not expect to commit to new contracts until additional progress is made on unpaid invoices and converting local currency to U.S. dollars. We have an agreement with PDVSA whereby 60 percent of our billings to PDVSA are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. PDVSA has previously paid U.S. dollar invoices in Bsf which increases our exposure to foreign currency devaluation. In 2008, we received notification from PDVSA that exchange of those U.S. dollar invoices previously paid in Bsf would be made only when supporting documentation had been approved. The supporting documentation was delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $37.5 million. We are unable to determine when payment will be received. Since 2005, the Venezuelan government has had exchange controls that fix the exchange rate at 2.15 Bsf to one U.S. dollar and prohibits us, as well as other companies, from converting Bsf into U.S. dollars. Since that time, we have, in compliance with applicable regulations, submitted three separate requests to the Venezuelan government seeking permission to convert existing Bsf balances into U.S. dollars. All three requests were approved by the Venezuelan government and we were permitted to remit U.S. dollars as dividends from the Venezuelan subsidiary to the U.S. based parent. These dividends reduced our exposure to currency devaluation in Venezuela. On July 22, 2008, we submitted another application with the Venezuela government requesting the approval to convert Bsf cash balances to U.S. dollars. When and if we receive approval from the Venezuelan government, our Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent as cash balances permit. While we have been successful in the past in obtaining government approval for conversion of Bsf 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 Bsf cash balances could increase and we would be exposed to increased risk of devaluation. Past devaluation losses may not be reflective of the potential for future devaluation losses. Venezuela continues to operate under exchange controls and the Venezuelan Bsf exchange rate has remained fixed at 2.15 Bsf to one U.S. dollar since March 2005. The exact amount and timing of any future devaluations attributable to the Venezuelan Bsf exchange rate is uncertain. At September 30, 2009, we had the equivalent of $45.3 million in cash denominated in Bsf’s exposed to the risk of currency devaluation. Additionally, we have other current assets including accounts receivable exposed to currency devaluation. While we are unable to predict the potential magnitude and timing of future devaluation in Venezuela, if current activity levels continue and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million. 102 NOTE 15 COMMITMENTS AND CONTINGENCIES COMMITMENTS From March 2005 through November 2008, we entered into separate drilling contracts to build and operate a total of 140 new FlexRigs. Eight of these 140 new rigs were contracted for work in International Land operations and the remaining 132 in U.S. Land operations. The construction of the 140 rigs is estimated to cost $2.2 billion, most of which was spent by the end of fiscal 2009. During construction, rig construction cost is included 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, 2009, we had commitments outstanding of approximately $63.1 million for the purchase of drilling equipment. LEASES We lease approximately 135,000 square feet of office space near downtown Tulsa, Oklahoma as well as other office space and equipment for use in operations. For operating leases that contain built-in pre-determined rent escalations, rent expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortized over the lease term. Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of one year at September 30, 2009 are as follows: Fiscal Year 2010 2011 2012 2013 2014 Thereafter Total Amount (in thousands) $ 8,165 6,145 3,050 2,569 2,271 9,982 $32,182 Total rent expense was $5.2 million, $4.2 million and $3.7 million for fiscal 2009, 2008 and 2007, respectively. CONTINGENCIES In August 2007, we 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 serious 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. During fiscal 2008, gross insurance proceeds of approximately $8.7 million were received and a gain from involuntary conversion of approximately $5.0 million was recorded. During the first quarter of fiscal 2009, we settled the claim and received approximately $0.3 million as final 103 payment. The proceeds were recorded as a gain from involuntary conversion in the Consolidated Statements of Income. In August 2005, our 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. The rig was insured at a value that approximated replacement cost. Capital costs incurred in conjunction with rebuilding the rig were capitalized in fiscal 2007 and are being depreciated. Insurance proceeds received through fiscal 2008 totaled approximately $24.5 million with approximately $21.9 recorded as a gain from involuntary conversion of long-lived assets. During fiscal 2009, proceeds of approximately $0.2 million were received as final settlement and recorded as a gain from involuntary conversion. Various legal actions, the majority of which arise in the ordinary course of business, are pending. We maintain insurance against certain business risks subject to certain deductibles. None of these legal actions are expected to have a material adverse effect on our financial condition, cash flows or results of operations. We are contingently liable to sureties in respect of bonds issued by the sureties in connection with certain commitments entered into by us in the normal course of business. We have agreed to indemnify the sureties for any payments made by them in respect of such bonds. NOTE 16 SEGMENT INFORMATION We operate principally in the contract drilling industry. Our 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 large oil and gas exploration companies. Our 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, we have aggregated our international operations into one reportable segment. Each reportable segment is a strategic business unit which is managed separately. Other includes non-reportable operating segments. Revenues included in Other consist primarily of rental income. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. We evaluate segment performance based on income or loss from operations (segment operating income) before income taxes which includes: revenues from external and internal customers (cid:129) (cid:129) direct operating costs (cid:129) depreciation and (cid:129) allocated general and administrative costs but excludes corporate costs for other depreciation, income from asset sales and other corporate income and expense. 104 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 we believe to be a reasonable reflection of the utilization of services provided. Segment operating income for all segments is a non-GAAP financial measure of our performance, as it excludes general and administrative expenses, corporate depreciation, income from asset sales and other corporate income and expense. We consider segment operating income to be an important supplemental measure of operating performance for presenting trends in our core businesses. We use this measure to facilitate period-to-period comparisons in operating performance of our reportable segments in the aggregate by eliminating items that affect comparability between periods. We believe that segment operating income is useful to investors because it provides a means to evaluate the operating performance of the segments 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 our operating performance in future periods. 105 Summarized financial information of our reportable segments for each of the years ended September 30, 2009, 2008 and 2007 is shown in the following table: (in thousands) 2009 Contract Drilling U.S. Land Offshore International Land Other External Sales Inter- Segment Total Sales Segment Operating Income (Loss) Depreciation Total Assets Additions to Long-Lived Assets $1,441,164 $ — $1,441,164 $573,708 $187,259 $2,962,062 $703,073 204,702 237,397 1,883,263 10,775 1,894,038 — — — 836 836 204,702 55,293 11,872 129,465 17,584 237,397 (7,227) 28,180 491,807 98,541 1,883,263 621,774 227,311 3,583,334 819,198 11,611 (7,032) 9,126 577,690 4,514 1,894,874 614,742 236,437 4,161,024 823,712 Eliminations — (836) (836) — — — — Total $1,894,038 $ — $1,894,038 $614,742 $236,437 $4,161,024 $823,712 2008 Contract Drilling U.S. Land Offshore International Land Other $1,542,038 $— $1,542,038 $605,718 $161,893 $2,660,232 $682,310 154,452 328,244 2,024,734 11,809 2,036,543 — — — 878 878 154,452 33,394 12,152 152,497 14,614 328,244 69,973 29,614 368,659 41,696 2,024,734 709,085 203,659 3,181,388 738,620 12,687 (7,996) 7,107 406,657 6,918 2,037,421 701,089 210,766 3,588,045 745,538 Eliminations — (878) (878) — — — — Total $2,036,543 $ — $2,036,543 $701,089 $210,766 $3,588,045 $745,538 2007 Contract Drilling U.S. Land Offshore International Land Other $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 — — — 828 828 123,148 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 5,466 373,715 14,803 1,630,486 599,267 146,042 2,885,369 825,448 Eliminations — (828) (828) — — — — Total $1,629,658 $ — $1,629,658 $599,267 $146,042 $2,885,369 $825,448 106 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 2009 2008 2007 $ 614,742 $ 701,089 $ 599,267 6,032 541 13,490 10,236 41,697 16,661 Corporate general and administrative costs and corporate depreciation (37,783) (31,999) (25,306) Operating income Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Total unallocated amounts 583,532 692,816 632,319 4,965 (13,490) — 808 (7,717) 5,038 (18,689) 21,994 (1,230) 7,113 4,234 (10,126) 65,458 (1,532) 58,034 Income before income taxes and equity in income of affiliate $ 575,815 $ 699,929 $ 690,353 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, 2009 2008 2007 Revenues United States Venezuela Argentina Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Argentina Ecuador Colombia Other Foreign Total $1,613,940 $1,687,075 $1,292,636 50,298 42,087 52,250 77,322 58,141 167,172 127,278 44,367 55,100 42,439 40,390 39,330 93,903 26,849 49,662 $1,894,038 $2,036,543 $1,629,658 $2,879,222 $2,461,726 $1,951,907 71,634 99,896 26,022 62,942 126,191 76,867 38,125 25,560 41,889 38,084 83,804 26,355 45,120 10,061 35,369 $3,265,907 $2,682,251 $2,152,616 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling business accounted for approximately 12.1 percent, 10.3 percent, and 5.5 percent of the total operating revenues during the years ended September 30, 2009, 2008 and 2007, respectively. Revenues from another company doing business with the 107 contract drilling business accounted for approximately 9.9 percent, 3.4 percent, and 1.3 percent of total operating revenues during the years ended September 30, 2009, 2008 and 2007, respectively. Collectively, the receivables from these customers were approximately $53.0 million and $60.7 million at September 30, 2009 and 2008, respectively. NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2009 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 $623,754 $520,300 $387,767 $362,217 222,420 145,275 1.38 1.36 183,338 103,738 .99 .98 91,432 53,044 .50 .50 86,342 51,488 .49 .48 2008 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 $456,663 $473,644 $522,517 $583,719 168,633 107,830 1.04 1.02 155,670 102,054 .98 .96 177,807 125,369 1.20 1.18 190,706 126,485 1.20 1.18 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 2009, net income includes an after-tax gain from the sale of assets of $0.6 million, $0.01 per share on a diluted basis. In the second quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $1.1 million, $0.01 per share on a diluted basis. In the third quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $1.1 million, $0.01 per share on a diluted basis. In the fourth quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $0.8 million, $0.01 per share on a diluted basis. In the first quarter of fiscal 2008, net income includes an after-tax gain from the involuntary conversion of long-lived assets of $3.1 million, $0.03 per share on a diluted basis. 108 In the second quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $3.3 million, $0.03 per share on a diluted basis and an after-tax gain from the sale of assets of $1.2 million, $0.01 per share on a diluted basis. In the third quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $10.0 million, $0.09 per share on a diluted basis, an after-tax gain from the sale of assets of $1.0 million, $0.01 per share on a diluted basis, and an after-tax gain from the involuntary conversion of long-lived assets of $3.5 million, $0.03 per share on a diluted basis. Included in net income for the third quarter of fiscal 2008 is an after-tax charge of $6.9 million, $0.07 per share on a diluted basis, from in-process research and development. In the fourth quarter of fiscal 2008, net income includes an after-tax gain from the sale of assets of $5.8 million, $0.05 per share on a diluted basis. Included in net income for the fourth quarter of fiscal 2008 is after-tax equipment abandonments of $7.3 million, $0.07 per share on a diluted basis. NOTE 18 SUBSEQUENT EVENTS We have evaluated events and transactions through November 24, 2009, and have determined we have no recognized subsequent events and one nonrecognized subsequent event. In September 2009, we accepted bids for the sale of one highly mobile rig in the U.S. Land segment. The net book value at September 30, 2009 was approximately $1.0 million and has been classified as ‘‘Assets held for sale’’ on our September 30, 2009 Balance Sheet. In October 2009, we sold U.S. Land Rig 147. Performance Graph The following performance graph reflects the yearly percentage change in our cumulative total stockholder return on common stock as compared with the cumulative total return on 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. Comparison of Cumulative Five Year Total Return $350 $300 $250 $200 $150 $100 $50 $0 2004 2005 2006 2007 2008 2009 Helmerich & Payne, Inc. S&P 500 Index S&P 500 Oil & Gas Drilling Index 9DEC200914481388 109 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 Randy A. Foutch*(***) Chairman and Chief Executive Officer Laredo Petroleum, Inc. Tulsa, Oklahoma Paula Marshall**(***) Chief Executive Officer, The Bama Companies, Inc. Tulsa, Oklahoma Hon. Francis Rooney*(***) Chief Executive Officer, Rooney Holdings, Inc. Former U.S. Ambassador to the Holy See, 2005-2008 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 W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer Douglas E. Fears Executive Vice President and Chief Financial Officer Stockholders’ Meeting The annual meeting of stockholders will be held on March 3, 2010. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 26, 2010. 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. Steven R. Mackey Executive Vice President, Secretary, and General Counsel Stock Transfer Agent and Registrar As of November 19, 2009, there were 663 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. 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. Gordon K. Helm Vice President and Controller 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 Annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of the Company’s website as soon as reasonably practicable after the Company electronically files such materials with, or furnishes it to, the SEC. 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; the Foreign Corrupt Practices Act Compliance 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. Annual reports, quarterly reports, current reports, amendments to those 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 27, 2009. 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 * Member, Audit Committee ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee 110 5DEC200714412927 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 ANNUAL REPORT FOR 2009