Helmerich & Payne
Annual Report 2011

Plain-text annual report

HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2011 18NOV201111532996 Helmerich & Payne, Inc. is the holding Company for He l m e ri c h & Pa y n e , In c . Helmerich & Payne International Drilling Co., a drilling contractor with land and offshore operations in the United States, South America, Trinidad, Africa and the Middle East. Holdings also include commercial real estate properties in the Tulsa, Oklahoma area, and an energy-weighted portfolio of securities valued at approximately $348 million as of September 30, 2011. F I N A N C I A L H I G H L I G H T S 17NOV201118344952 Years Ended September 30, 2011 2010 2009 Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets (in thousands, except per share amounts) $2,543,894 434,186 3.99 .250 694,264 5,003,891 $1,875,162 156,312 1.45 .210 329,572 4,265,370 $1,843,740 353,545 3.31 .200 876,839 4,161,024 Financial & Operating Review H E L M E R I C H & PA Y N E , I N C . Years Ended September 30, 2011 2010 2009 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues Operating Costs, excluding depreciation Depreciation** General and Administrative Expense Operating Income (Loss) Interest and Dividend Income Gain on Sale of Investment Securities Interest Expense Income (Loss) from Continuing Operations Net Income Diluted Earnings Per Common Share: Income (Loss) 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 $88,075 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† †Excludes discontinued operations 2 $2,543,894 1,432,602 315,468 91,452 702,511 1,951 913 17,355 434,668 434,186 $1,875,162 1,071,959 262,658 81,479 451,796 1,811 — 17,158 286,081 156,312 $1,843,740 944,780 227,535 58,822 608,875 2,755 — 13,590 380,546 353,545 3.99 3.99 2.66 1.45 3.56 3.31 $ 364,246 537,034 347,924 3,677,070 5,003,891 235,000 3,270,047 694,264 $ 63,020 417,888 320,712 3,275,020 4,265,370 360,000 2,807,465 329,572 $ 96,142 157,103 356,404 3,194,273 4,161,024 420,000 2,683,009 876,839 221 4 23 9 24 281 99 0 16 86 77 70 182 11 27 9 28 257 87 0 17 73 80 71 163 11 27 9 33 243 76 29 39 68 89 70 2008 2007 2006 2005 2004 2003 2002 2001 $1,869,371 987,838 195,343 56,429 640,084 3,524 21,994 18,721 420,258 461,738 3.93 4.32 $1,502,380 788,967 137,187 47,401 586,506 4,143 65,458 9,591 415,924 449,261 3.95 4.27 $1,140,219 606,945 93,363 51,873 395,341 9,688 19,866 6,499 269,852 293,858 2.54 2.77 $ 733,902 435,057 88,483 41,015 182,355 5,772 26,969 12,416 120,666 127,606 1.16 1.23 $ 532,759 375,600 139,591 37,661 (14,698) 1,622 25,418 12,541 (1,016) 4,359 (0.01) 0.04 $ 472,407 322,553 76,748 41,003 35,845 2,467 5,529 12,357 16,417 17,873 0.17 0.17 $ 472,865 319,330 56,208 36,563 61,946 3,624 24,820 993 55,017 63,517 0.54 0.63 $ 479,132 295,021 46,134 28,180 113,890 9,128 1,189 1,715 71,046 144,254 0.70 1.42 $ 77,549 274,519 199,266 2,605,384 3,588,045 475,000 2,265,474 697,906 $ 67,445 209,766 223,360 2,068,812 2,885,369 445,000 1,815,516 885,583 $ 32,193 126,540 218,309 1,399,974 2,134,712 175,000 1,381,892 521,847 $ 284,460 378,496 178,452 897,504 1,663,350 200,000 1,079,238 78,677 $ 63,785 157,266 161,532 913,338 1,406,844 200,000 914,110 86,057 $ 29,763 82,712 158,770 983,026 1,417,770 200,000 917,251 233,850 $ 45,699 87,584 150,175 824,815 1,227,313 100,000 895,170 298,295 $ 127,395 201,549 203,271 565,195 1,300,121 50,000 1,026,477 152,123 146 12 27 9 19 213 100 83 80 96 75 72 118 12 27 9 16 182 100 93 87 97 65 89 73 12 28 9 16 138 100 100 95 99 69 95 50 12 29 11 14 116 100 99 82 94 53 80 3 48 11 28 11 19 117 99 91 67 87 48 47 43 11 29 12 21 116 97 89 58 81 51 42 26 11 29 12 19 97 96 97 70 84 83 59 13 11 25 10 20 79 100 89 99 97 98 69 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 1 1 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, 2011 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 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, 2011 the aggregate market value of the voting stock held by non-affiliates was $7,107,745,833 Number of shares of common stock outstanding at November 17, 2011: 107,145,588 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, 2011 . . . . . . . . . . . . . (2) Proxy Statement for Annual Meeting of Stockholders to be held March 7, 2012 . . . . . . . . . . . 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 35 THROUGH 67 OF THE COMPANY’S ANNUAL REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. EXCEPT AS REQUIRED BY LAW, 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, 2011 TABLE OF CONTENTS Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Properties Legal Proceedings [Removed and Reserved.] Executive Officers of the Company PART I PART II Item 2. Item 3. Item 4. Item 5. Item 6. Item 7. 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 ii Page 1 6 11 12 18 18 19 20 20 21 21 21 21 22 25 26 26 26 26 26 27 31 (This page has been left blank intentionally.) 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, 2011 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, Alabama, Montana, North Dakota and West Virginia. 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 2011: Ecuador, Colombia, Argentina, Mexico, Tunisia and Bahrain. We are also engaged in the ownership, development and operation of commercial real estate and the 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 centralized finance and legal organizations. 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 our existing drilling rig technology. 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. On June 30, 2010, the Venezuelan government seized 11 rigs owned by our Venezuelan subsidiary and associated real and personal property. We have sued the Bolivarian Republic of Venezuela and related governmental entities for damages sustained as a result of the seizure of our Venezuelan drilling business. We are also participating in two arbitrations against non-Venezuelan entities related to the seizure of our property in Venezuela (For further information, see Item 3. Legal Proceedings). We are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. Our financial statements have been prepared with the net assets, results of operations, and cash flows of the Venezuelan operations presented as discontinued operations. The operations from our Venezuelan subsidiary were previously an operating segment within our International Land drilling segment. CONTRACT DRILLING General We believe that we are one of the major land and offshore platform 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 major international oil companies. In fiscal 2011, we received approximately 57 percent of our consolidated operating revenues from our ten largest contract drilling customers. Occidental Oil and Gas Corporation, Devon Energy Production Co. LP, and EOG Resources, Inc. (respectively, ‘‘Oxy’’, ‘‘Devon’’ and ‘‘EOG’’), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Oxy on a world-wide basis, for Devon in U.S. land operations, and for EOG in U.S. land and offshore operations. Revenues from drilling services performed for Oxy, Devon and EOG in fiscal 2011 accounted for approximately 12 percent, 11 percent and 8 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 drill string 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 highly mobile/depth flexible land drilling rigs (individually the ‘‘FlexRig(cid:4)’’). 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 greater depth flexibility and provides greater operating efficiency. The original rigs were designated as FlexRig1 and FlexRig2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. In 2001, we announced that we would build the next generation of FlexRigs, known as ‘‘FlexRig3 rigs’’, 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. FlexRig3 rigs were designed to target well depths similar to prior generation FlexRigs. In 2006, we placed into service our first FlexRig4. While FlexRig4s are similar to our 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 additional environmental and safety design. This design permits the installation of a pipe handling system which allows the rig to be more efficiently operated and eliminates the need for a casing stabber in the mast. While the FlexRig4 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. In 2011, we announced the introduction of the FlexRig5 design. The FlexRig5 is suited for long lateral drilling of multiple wells from a single location, which is well suited for unconventional shale reservoirs. The new design preserves the key performance features of FlexRig3 combined with a bi-directional pad drilling system and equipment capacities suitable for wells in excess of 24,000 feet of measured depth. Since 1998, we have built and delivered 232 FlexRigs, including 129 FlexRig3s, 85 FlexRig4s, and 1 FlexRig5. Of the total Flexrigs built to date, 159 have been built in the last five years. As of November 17, 2011, an additional 47 new FlexRigs remained under construction. The effective use of technology is important to the maintenance of our competitive position within the drilling industry. We expect to continue to refine our existing technology and develop new technology in the future. 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. 2 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 2011, 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 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 in over ten years. We believe that under current market conditions, ‘‘footage’’ and ‘‘turnkey’’ contract rates do not adequately compensate us 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 generally have a minimum term of at least one year but 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. 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. As of September 30, 2011, we had 158 rigs under fixed term contracts. While the original duration for these current fixed term contracts are for six-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. 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, 2011 and 2010 was $3,789 million and $2,449 million, respectively. The increase in backlog at September 30, 2011 from September 30, 2010, is primarily due to the execution of additional fixed-term contracts for the operation of new FlexRigs. Approximately 61.0 percent of the total September 30, 2011 backlog is not reasonably expected to be filled in fiscal 2012. A portion of the backlog represents term contracts for new rigs that will be constructed in the future. The following table sets forth the total backlog by reportable segment as of September 30, 2011 and 2010, and the percentage of the September 30, 2011 backlog not reasonably expected to be filled in fiscal 2012: Reportable Segment U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Backlog Revenue 9/30/2011 9/30/2010 (in millions) $3,279 98 412 $3,789 $1,999 139 311 $2,449 Percentage Not Reasonably Expected to be Filled in Fiscal 2012 60.2% 56.1% 71.1% 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 3 gulf coast. Therefore, disruptions in rig component deliveries may occur. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A. Risk Factors. U.S. LAND DRILLING At the end of September 2011, 2010 and 2009, we had 248, 220 and 201, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2011 increased by a net of 28 rigs from the end of fiscal 2010. The increase is due to 35 new FlexRigs being completed and placed into service, 5 transferred from international operations, 1 rig transferred to international operations, 4 rigs sold during fiscal 2011 and 7 mechanical highly mobile rigs being removed from service. Our U.S. Land operations contributed approximately 83 percent ($2,100.5 million) of our consolidated operating revenues during fiscal 2011, compared with approximately 75 percent ($1,412.5 million) of consolidated operating revenues during fiscal 2010 and approximately 78 percent ($1,441.2 million) of consolidated operating revenues during fiscal 2009. Rig utilization was approximately 86 percent in fiscal 2011 and approximately 73 percent in fiscal 2010, up from approximately 68 percent in fiscal 2009. Our fleet of FlexRigs increased to an average utilization of approximately 99 percent during fiscal 2011, while our conventional and highly mobile rigs had a combined average utilization of approximately 11 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2011, 224 land rigs were working out of 248 available rigs. OFFSHORE DRILLING Our Offshore operations contributed approximately 8 percent in fiscal year 2011 ($201.4 million) of our consolidated operating revenue compared to 11 percent in both fiscal years 2010 and 2009 ($202.7 million and $204.7 million, respectively) of our consolidated operating revenues. Rig utilization in fiscal 2011 was approximately 77 percent compared to approximately 80 percent in fiscal 2010 and approximately 89 percent in fiscal 2009. At the end of fiscal 2011, we had eight of our nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 53 percent of offshore revenues during fiscal 2011. 4 International Land Drilling General Our International Land operations contributed approximately 9 percent ($226.8 million) of our consolidated operating revenues during fiscal 2011, compared with approximately 13 percent ($247.2 million) of consolidated operating revenues during fiscal 2010 and 10 percent ($187.1 million) in fiscal 2009. Rig utilization in fiscal 2011 was 70 percent, 71 percent in fiscal 2010 and 70 percent in fiscal 2009. Argentina At the end of fiscal 2011, we had nine rigs in Argentina. Our utilization rate was approximately 49 percent during fiscal 2011, approximately 53 percent during fiscal 2010 and approximately 52 percent during fiscal 2009. Revenues generated by Argentine drilling operations contributed approximately 2 percent ($44.2 million) of our consolidated operating revenues during fiscal 2011 compared with approximately 3 percent ($55.9 million) in fiscal 2010 and 2 percent ($42.1 million) in fiscal 2009. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 1 percent of consolidated operating revenues and approximately 15 percent of international operating revenues during fiscal 2011. The Argentine drilling contracts are primarily with large international or national oil companies. Colombia At the end of fiscal 2011, we had six rigs in Colombia. Our utilization rate was approximately 83 percent during fiscal 2011, approximately 71 percent during fiscal 2010 and approximately 88 percent during fiscal 2009. Revenues generated by Colombian drilling operations contributed approximately 3 percent of our consolidated operating revenues during fiscal 2011 and 2010 ($74.5 million and $57.5 million in fiscal 2011 and 2010, respectively), compared with 4 percent ($77.3 million) of our consolidated operating revenues during fiscal 2009. Revenues from drilling services performed for our largest customer in Colombia totaled approximately 1 percent of consolidated operating revenues and approximately 12 percent of international operating revenues during fiscal 2011. The Colombian drilling contracts are primarily with large international or national oil companies. Ecuador At the end of fiscal 2011, we had four rigs in Ecuador. The utilization rate in Ecuador was 85 percent in fiscal 2011, compared to 100 percent in fiscal 2010 and 2009. Revenues generated by Ecuadorian drilling operations contributed approximately 2 percent ($42.6 million) of our consolidated operating revenues during fiscal 2011 compared with approximately 3 percent in both fiscal years 2010 and 2009 ($52.1 million and $52.3 million in fiscal 2010 and 2009, respectively). Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 1 percent of consolidated operating revenues and approximately 13 percent of international operating revenues during fiscal 2011. The Ecuadorian 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 2011 we had two rigs in Tunisia, and three rigs in Bahrain. An additional rig is en route to Bahrain subsequent to September 30, 2011. 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 102 through 106 of our Annual Report. EMPLOYEES We had 7,694 employees within the United States (17 of which were part-time employees) and 1,030 employees in international operations as of September 30, 2011. 5 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 108 of our Annual Report. 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. Our offshore and land operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. Our drilling operations are subject to the many hazards inherent in the business, including inclement weather, blowouts, well fires, loss of well control, pollution, and reservoir damage. These hazards could cause significant environmental damage, personal injury, suspension of drilling operations, serious damage or destruction of equipment and property and substantial damage to producing formations and surrounding lands and waters. Our offshore drilling operations are also subject to potentially greater environmental liability, including pollution of offshore waters and related negative impact on wildlife and habitat, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. Our offshore operations may also be negatively affected by blowouts or uncontrolled release of oil by third parties whose offshore operations are unrelated to our operations. 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, the frequency of which may increase with any climate change. 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, and our principal fabricator and other vendors are also located in the gulf coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage. We have indemnification agreements with many of our customers and we also maintain liability and other forms of insurance. In general, our drilling contracts contain contractual rights to indemnity from our customer for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their contractual indemnification obligations to us. Accordingly, we may be unable to transfer these risks to our drilling customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect our business, financial condition and 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. However, we self-insure our deductible as well as a significant portion of the estimated replacement cost of our offshore rigs and our land rigs and equipment. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and ‘‘named wind storm’’ risk in the Gulf of Mexico. We have insurance coverage for comprehensive general liability, automobile liability, worker’s compensation and employer’s liability, and certain other specific risks. 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. The Company self-insures a number of other risks including loss of earnings and 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. If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial 6 condition and results of operations. Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal 2012, that insurance coverage will continue to be available at rates considered reasonable or that our coverage will respond to a specific loss. Further, we may experience difficulties in collecting from our insurers or our insurers may deny all or a portion of our claims for insurance coverage. 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. A sluggish global economy may affect our business. As a result of volatility in oil and natural gas prices and a continuing sluggish global economic environment, we are unable to determine whether our customers will maintain 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 level of operations, fulfill their commitments and/or fund future operations and obligations. The current global economic environment may impact industry fundamentals and result in reduced demand for drilling rigs. These conditions could have a material adverse effect on our business, financial condition and results of operations. 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, environmental impact, 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. 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 2011, we received approximately 57 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 32 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 could have a material adverse effect on our business, financial condition and results of operations. 7 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. On June 30, 2010, the Venezuelan government seized 11 rigs and associated real and personal property owned by our Venezuelan subsidiary. 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. Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2011, approximately 9 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2011, approximately 71 percent of the international operating revenues were from operations in South America. All of the South American operating revenues were from Argentina, Colombia and Ecuador. 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. 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. 8 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, 2011, we had a portfolio of securities with a total fair value of $348 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 17, 2011, the fair value of the portfolio had increased to approximately $431.2 million. 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, pollution, disposal of hazardous substances and oil field waste. The United States and various other countries have environmental regulations which affect drilling operations. The cost of compliance with these laws could be substantial. A failure to comply with these laws and regulations could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States impose a variety of requirements on ‘‘responsible parties’’ related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of drilling rigs, we may be deemed to be a responsible party under these laws and regulations. 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 costs have 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. Regulation of greenhouse gases and climate change could have a negative impact on our business. Some scientific studies have suggested that emissions of certain gases, commonly referred to as ‘‘greenhouse gases’’ (‘‘GHGs’’) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. The United States Congress is considering legislation to reduce GHG emissions. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding GHG emissions could have a material adverse impact on our business, financial condition and results of operations. New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Members of the U.S Congress and the U.S. Environmental Protection Agency, or the EPA, are reviewing more stringent regulation of hydraulic fracturing, a technology which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the U.S. Congress and the EPA are studying whether there is any link between hydraulic fracturing and soil or ground water contamination or any impact on public health. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have and others are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event we engage in any hydraulic fracturing activities, any new laws, regulation or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs or third party or governmental claims, additional burdens that could serve to delay or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations, increased costs of compliance and doing 9 business, or delay in the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Our business and results of operations may be adversely affected by foreign currency devaluation. Contracts for work in foreign countries generally provide for payment in U.S. dollars; however, government-owned petroleum companies may in the future require that a greater proportion of these payments be made in local currencies. Based upon current information, we believe that our exposure to potential losses from currency devaluation in foreign countries is immaterial. However, in the event of future payments in local currencies or an inability to exchange local currencies for U.S. dollars, we may incur currency devaluation losses which could have a material adverse impact on our business, financial condition and results of operations. 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 current global economic environment may affect the customer’s ability to pay the early termination payment. 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. 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. Any such changes in technology could have a material adverse effect on our business, financial condition and results of operations. Competition for experienced 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 retain, and in some cases find, qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain or find a sufficient number of qualified personnel could have a material adverse effect on our business, financial condition and results of operations. Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations. Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition and results of operations. 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 2011 fiscal year and that remain unresolved. 11 Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning our U.S. land and offshore drilling rigs as of September 30, 2011: Location FLEXRIGS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS NORTH DAKOTA NORTH DAKOTA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS NEW MEXICO COLORADO TEXAS PENNSYLVANIA TEXAS OKLAHOMA TEXAS TEXAS TEXAS NEW MEXICO OKLAHOMA WEST VIRGINIA TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS OKLAHOMA CALIFORNIA TEXAS TEXAS NORTH DAKOTA CALIFORNIA Rig Optimum Depth (Feet) Rig Type Drawworks: Horsepower 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) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 164 165 166 167 168 169 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 229 230 231 232 233 234 235 236 237 238 239 240 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 12 Location NORTH DAKOTA TEXAS TEXAS TEXAS TEXAS LOUISIANA TEXAS TEXAS OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA TEXAS CALIFORNIA CALIFORNIA TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS COLORADO PENNSYLVANIA WYOMING TEXAS WYOMING NORTH DAKOTA NORTH DAKOTA COLORADO TEXAS COLORADO TEXAS TEXAS TEXAS PENNSYLVANIA PENNSYLVANIA WYOMING PENNSYLVANIA TEXAS ARKANSAS PENNSYLVANIA NORTH DAKOTA NORTH DAKOTA NORTH DAKOTA TEXAS TEXAS UTAH TEXAS Rig 241 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 293 294 295 296 297 298 299 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 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 14,000 14,000 14,000 14,000 14,000 14,000 14,000 13 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 (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) 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 1,500 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 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location NEW MEXICO TEXAS* TEXAS TEXAS WYOMING TEXAS TEXAS WYOMING COLORADO NORTH DAKOTA WYOMING UTAH TEXAS TEXAS TEXAS COLORADO NORTH DAKOTA NORTH DAKOTA WYOMING UTAH PENNSYLVANIA COLORADO COLORADO COLORADO NORTH DAKOTA NORTH DAKOTA WYOMING TEXAS ARKANSAS NORTH DAKOTA COLORADO TEXAS TEXAS TEXAS TEXAS ARKANSAS COLORADO TEXAS TEXAS TEXAS TEXAS CALIFORNIA CALIFORNIA TEXAS TEXAS COLORADO WEST VIRGINIA NEW MEXICO TEXAS NEW MEXICO PENNSYLVANIA TEXAS TEXAS OKLAHOMA OKLAHOMA Rig 300 301 302 303 304 305 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 323 324 325 326 327 328 329 330 331 332 340 341 342 343 344 345 346 347 348 349 351 352 353 354 355 356 370 371 372 373 374 375 Optimum Depth (Feet) 14,000 8,000 8,000 8,000 8,000 8,000 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 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 14,000 14,000 8,000 8,000 18,000 18,000 18,000 18,000 18,000 18,000 14 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 (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) Drawworks: Horsepower 1,500 1,150 1,150 1,150 1,150 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 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 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 Location OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA CALIFORNIA CALIFORNIA TEXAS TEXAS TEXAS PENNSYLVANIA NORTH DAKOTA OKLAHOMA TEXAS TEXAS TEXAS TEXAS NORTH DAKOTA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS NEW MEXICO TEXAS TEXAS OKLAHOMA TEXAS TEXAS CALIFORNIA TEXAS CALIFORNIA OKLAHOMA CALIFORNIA OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS NORTH DAKOTA TEXAS CALIFORNIA TEXAS TEXAS TEXAS CALIFORNIA OKLAHOMA Rig 376 377 378 379 380 381 382 383 384 385 386 387 388 389 390 391 392 393 394 395 396 397 398 399 415 416 417 418 419 420 421 422 423 424 425 426 427 428 429 430 431 432 433 434 435 436 437 438 439 440 441 442 443 444 445 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 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 15 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 (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) 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 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location NORTH DAKOTA OKLAHOMA NORTH DAKOTA COLORADO OKLAHOMA TEXAS NORTH DAKOTA TEXAS PENNSYLVANIA HIGHLY MOBILE RIGS OKLAHOMA TEXAS TEXAS UTAH CONVENTIONAL RIGS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA# TEXAS# LOUISIANA OKLAHOMA LOUISIANA TEXAS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS LOUISIANA OKLAHOMA TEXAS LOUISIANA TEXAS TEXAS LOUISIANA LOUISIANA OFFSHORE PLATFORM RIGS TRINIDAD GULF OF MEXICO GULF OF MEXICO LOUISIANA GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO Rig 446 447 448 449 450 453 454 455 500 158 155 146 154 110 96 118 119 120 122 162 79 80 89 92 94 98 137 149 72 73 125 134 136 157 161 163 203 205 206 100 105 107 201 202 204 Optimum Depth (Feet) 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 20,000 Rig Type AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig5) Drawworks: Horsepower 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 10,000 14,000 16,000 16,000 12,000 16,000 16,000 16,000 16,000 16,000 18,000 20,000 20,000 20,000 20,000 20,000 20,000 26,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 20,000 20,000 20,000 30,000 30,000 30,000 30,000 30,000 30,000 SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Self-Erecting Self-Erecting Self-Erecting Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 900 1,200 1,200 1,500 700 1,000 1,200 1,200 1,200 1,700 1,500 2,000 1,500 1,500 1,500 1,500 1,500 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 2,500 2,000 1,500 3,000 3,000 3,000 3,000 3,000 3,000 * Rig moved to Bahrain in the first quarter of fiscal 2012 # Rig sold subsequent to September 30, 2011 16 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, 2007 2008 2009 2010 2011 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) . . . . . . . . . . . . . . . . . . . . . 185 157 97% 96% 68% 73% 86% 248 220 201 9 9 9 65% 75% 89% 80% 77% 9 9 (1) A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract. The following table sets forth certain information concerning our international drilling rigs as of September 30, 2011: Location Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina Bahrain Bahrain Bahrain Colombia Colombia Colombia Colombia Colombia Colombia Ecuador Ecuador Ecuador Ecuador Tunisia Tunisia Rig 335 336 337 338 123 175 177 139 151 291 292 339 333 334 176 190 133 152 132 121 117 138 228 242 Optimum Depth (Feet) Rig Type Drawworks: Horsepower AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) SCR SCR SCR SCR SCR AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) SCR SCR SCR SCR SCR SCR SCR SCR AC (FlexRig3) AC (FlexRig3) 1,150 1,150 1,150 1,150 2,100 3,000 3,000 3,000 3,000 1,150 1,150 1,150 1,150 1,150 1,500 2,000 3,000 3,000 1,500 1,700 2,500 2,500 1,500 1,500 8,000 8,000 8,000 8,000 26,000 30,000 30,000 30,000+ 30,000+ 8,000 8,000 8,000 8,000 8,000 18,000 26,000 30,000 30,000+ 18,000 20,000 26,000 26,000 18,000 18,000 17 The following table sets forth information with respect to the utilization of our international drilling rigs for the periods indicated: Years ended September 30, 2007 2008 2009 2010 2011 Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1)(2) . . . . . . . . . . . . . . . . . . . . . 19 16 33 89% 72% 70% 71% 70% 24 28 (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 54 of our Annual Report under the caption, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’ Item 3. LEGAL PROCEEDINGS 1. Pending Investigation by the U.S. Attorney. In May 2010, one of our employees reported certain possible choke manifold testing irregularities at one offshore platform rig. Operations were promptly suspended on that rig after receiving the employee’s report. The Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement) was promptly notified of the employee’s report and it conducted an initial investigation of this matter. Upon conclusion of the initial investigation, we were permitted to resume normal operations on the rig. Also, we promptly commenced an internal investigation of the employee’s allegations. Our internal investigation found that certain employees on the rig failed to follow our policies and procedures, which resulted in termination of those employees. There were no spills or discharges to the environment. The U.S. Attorney for the Eastern District of Louisiana has commenced a grand jury investigation, which is ongoing. We received, and have complied with, a subpoena for documents in connection with that investigation. Certain of our employees have testified or are scheduled to testify before the grand jury. In late April 2011, the Company was advised that it is a subject of this investigation. Although we presently believe that this matter will not have a material adverse effect on the Company, we can provide no assurances as to the timing or eventual outcome of this investigation. 2. Venezuela Expropriation. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. (‘‘Petroleo’’) and PDVSA Petroleo, S.A. (‘‘PDVSA’’). We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in two arbitrations against third parties not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $75 million relating to the seizure of our property in Venezuela. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. Item 4. [Removed and reserved.] 18 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, 88 . Chairman of the Board since 1987; Director since 1949 Hans Helmerich, 53 . . . . President and Chief Executive Officer since 1989; Director since 1987 John W. Lindsay, 50 . . . . Executive Vice President and Chief Operating Officer since 2010; Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. since 2006; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. from 1997 to 2006 Steven R. Mackey, 60 . . . Executive Vice President, Secretary, General Counsel and Chief Administrative Officer since March 2010; Executive Vice President, Secretary and General Counsel from June 2008 to March 2010; Secretary since 1990; Vice President and General Counsel since 1988 Juan Pablo Tardio, 46 . . . Vice President and Chief Financial Officer since April 2010; Director of Investor Relations from January 2008 to April 2010; Manager of Investor Relations from August 2005 to January 2008 19 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 2010 2011 High Low High Low First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $46.24 49.13 43.72 42.03 $36.18 36.23 32.34 35.56 $49.46 69.72 70.47 73.40 $39.65 47.53 57.08 40.60 We paid quarterly cash dividends during the past two fiscal years as shown in the following table: Quarter First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid per Share Total Payment Fiscal Fiscal 2010 $.05 .05 .05 .06 2011 $.06 .06 .06 .07 2010 2011 $5,286,530 5,300,194 5,303,994 6,363,377 $6,376,282 6,408,617 6,438,106 7,518,604 Payment of future dividends will depend on earnings and other factors. As of November 17, 2011, there were 578 record holders of our common stock as listed by our 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 35 through 67 of our Annual Report. Amounts for fiscal years 2007, 2008 and 2009 have been restated to reflect the Venezuelan operations as discontinued operations. Refer to Part I, Item 1 above for additional information regarding discontinued operations. 20 Five-year Summary of Selected Financial Data 2007 2008 2009 2010 2011 Operating revenues . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . Income (loss) from discontinued operations Net Income . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per share from continuing operations . . . . . . . . . . . . . . . . . . . . . . Basic earnings (loss) per share from discontinued operations . . . . . . . . . . . . Basic earnings per share . . . . . . . . . . . . . . Diluted earnings per share from continuing operations . . . . . . . . . . . . . . Diluted earnings (loss) per share from discontinued operations . . . . . . . . . . . . Diluted earnings per share . . . . . . . . . . . . Total assets* . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . Cash dividends declared per common $1,502,380 415,924 33,337 449,261 4.03 0.32 4.35 3.95 (in thousands except per share amounts) $1,843,740 380,546 (27,001) 353,545 $1,869,371 420,258 41,480 461,738 $1,875,162 286,081 (129,769) 156,312 $2,543,894 434,668 (482) 434,186 4.02 0.40 4.42 3.93 3.61 2.70 (0.26) 3.35 (1.23) 1.47 3.56 2.66 4.06 — 4.06 3.99 0.32 4.27 2,885,369 445,000 0.39 4.32 3,588,045 475,000 (0.25) 3.31 4,161,024 420,000 (1.21) 1.45 4,265,370 360,000 — 3.99 5,003,891 235,000 share . . . . . . . . . . . . . . . . . . . . . . . . . . 0.1800 0.1850 0.2000 0.2200 0.2600 * Total assets for all years include amounts related to discontinued operations 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 35 through 67 of our Annual Report under the caption ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’ Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found under the caption ‘‘Risk Factors’’ beginning on page 6 of this Report and on, and is incorporated by reference to, the following pages of our Annual Report under Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to Consolidated Financial Statements: Market Risk • Foreign Currency Exchange Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • Commodity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • Interest Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • Equity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 64-65 65-66 66-67 67 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found on, and is incorporated by reference to, pages 69 through 107 of our Annual Report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 21 Item 9A. CONTROLS AND PROCEDURES a) Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this 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, 2011. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that: • 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, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and • 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 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, as amended. 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 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, 2011. 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. 22 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 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. * * * 23 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, 2011, 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, 2011, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2011 and 2010 and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2011 and our report dated November 23, 2011 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Tulsa, Oklahoma November 23, 2011 24 Item 9B. OTHER INFORMATION None. 25 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,’’ ‘‘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 7, 2012, to be filed with the SEC not later than 120 days after September 30, 2011. 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 2011’’ and ‘‘Compensation Committee Interlocks and Insider Participation’’ in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2012, to be filed with the SEC not later than 120 days after September 30, 2011. 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 7, 2012, to be filed with the SEC not later than 120 days after September 30, 2011. 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 7, 2012, to be filed with the SEC not later than 120 days after September 30, 2011. 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 7, 2012, to be filed with the SEC not later than 120 days after September 30, 2011. 26 Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV a) 1. Financial Statements: The following appear in our Annual Report to Stockholders on the pages indicated below and are incorporated herein by reference: Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Income for the Years Ended September 30, 2011, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 68 69 Consolidated Balance Sheets at September 30, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . 70-71 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2011, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2011, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 73 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74-107 2. Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto. 3. Exhibits. The following documents are included as exhibits to this Annual Report. Exhibits incorporated by reference or which are otherwise not included herein are available free of charge upon written request. 3.1 3.2 4.1 4.2 *10.1 *10.2 *10.3 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 September 10, 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 Exhibit 1 of the Company’s Form 8-K filed on 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. 27 *10.4 *10.5 *10.6 *10.7 10.8 10.9 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. 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. 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. 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. 10.10 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 on July 21, 2009, SEC File No. 001-04221. 10.11 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. 10.12 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. *10.13 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 7, 2009, SEC File No. 001-04221. *10.14 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. *10.15 Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on December 8, 2009, SEC File No. 001-04221. 28 *10.16 Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: Nonqualified Stock Option Agreement, Incentive Stock Option Agreement, and Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.3 of the Company’s Form 8-K filed on December 8, 2009, SEC File No. 001-04221. *10.17 Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers are incorporated herein by reference to Exhibit 10.4 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221. *10.18 Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers are incorporated herein by reference to Exhibit 10.5 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221. *10.19 Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan is incorporated herein by reference to Appendix ‘‘A’’ of the Company’s Proxy Statement on Schedule 14A filed on January 26, 2011. 10.20 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. 10.21 Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on July 18, 2007, SEC File No. 001-04221. 10.22 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. 10.23 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. 10.24 10.25 Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. 10.26 Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. 10.27 Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. *10.28 *10.29 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. 29 *10.30 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. 13. 21. 23.1 31.1 31.2 32. 101. The Company’s Annual Report to Stockholders for fiscal 2011. 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. 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, 2011, filed on November 23, 2011, 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. * Management or Compensatory Plan or Arrangement. 30 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 23, 2011 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 23, 2011 Randy A. Foutch, Director November 23, 2011 By /s/ HANS HELMERICH By /s/ W. H. HELMERICH, III Hans Helmerich, Director & CEO Date: November 23, 2011 W. H. Helmerich, III, Director Date: November 23, 2011 By /s/ PAULA MARSHALL Paula Marshall, Director Date: November 23, 2011 By /s/ FRANCIS ROONEY Francis Rooney, Director Date: November 23, 2011 By /s/ EDWARD B. RUST, JR. By /s/ JOHN D. ZEGLIS Edward B. Rust, Jr., Director Date: November 23, 2011 John D. Zeglis, Director Date: November 23, 2011 By /s/ JUAN PABLO TARDIO By /s/ GORDON K. HELM Juan Pablo Tardio (Principal Financial Officer) Date: November 23, 2011 Gordon K. Helm (Principal Accounting Officer) Date: November 23, 2011 31 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 23, 2011 /s/ HANS HELMERICH Hans Helmerich President and Chief Executive Officer 32 I, Juan Pablo Tardio, 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 23, 2011 /s/ JUAN PABLO TARDIO Juan Pablo Tardio Vice President and Chief Financial Officer 33 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, 2011 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 Juan Pablo Tardio, as Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that: (1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; 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 23, 2011 /s/ JUAN PABLO TARDIO Juan Pablo Tardio Vice President and Chief Financial Officer Date: November 23, 2011 34 Management’s Discussion & Analysis of Financial Condition and Results of Operations Helmerich & Payne, Inc. Risk Factors and Forward-Looking Statements The following discussion should be read in conjunction with 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, expropriation of real and personal property, 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 & 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 Annual Report are important factors (but not necessarily inclusive of all important factors) that 35 could cause actual results to differ materially from those expressed in any forward-looking statement made by us or persons acting on our behalf. Except as required by law, we undertake no duty to update or revise our forward-looking statements based on changes of internal estimates or expectations or otherwise. Executive Summar y Helmerich & Payne, Inc. is primarily a contract drilling company with a total fleet of 281 drilling rigs at September 30, 2011. Our contract drilling segments include the U.S. Land segment with 248 rigs, the Offshore segment with nine offshore platform rigs and the International Land segment with 24 rigs at September 30, 2011. Notwithstanding the uncertainty related to the global economy and its potential impact on future energy prices, drilling activity continued to expand in 2011. As U.S. land industry rig counts approached 2008 peak heights at the end of fiscal 2011, our U.S. Land segment activity increased to record levels. At September 30, 2011, we had 224 active rigs in the U.S. land market, as compared to 185 active rigs at the same time during the prior year. This expansion was mostly attributable to the construction and delivery during 2011 of new FlexRigs, all with fixed multi-year contracts. As we move into 2012, we expect to continue this growth at a cadence of four new FlexRigs per month. Our Offshore segment remained stable in 2011. While our International Land segment experienced decreased operating income in 2011, we believe there is long-term growth potential as international markets recover and the unconventional shale plays spread world-wide. Drilling today involves more complex well designs directed at oil and liquids rich shale plays. We believe we offer high efficiency rigs with 36 technology that allows our customers to achieve lower total well costs while also providing safety and reduced environmental impact. As further discussed in Note 2 of the Consolidated Financial Statements, our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government. The subsidiary was previously classified as an operating segment within our International Land segment. Accordingly, we reclassified the financial statements and related disclosures for all periods presented other than fiscal 2010 and 2011. These reclassifications had no impact on net income, total assets or total shareholders’ equity. Unless otherwise indicated, the following discussion pertains only to our continuing operations. All historical statements and statistical data in the following discussion have been restated to exclude discontinued operations. Unless otherwise indicated, references to 2011, 2010 and 2009 in the following discussion are referring to our fiscal year 2011, 2010 and 2009. Results of Operations All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2011 was $434.2 million ($3.99 per share), compared with $156.3 million ($1.45 per share) for 2010 and $353.5 million ($3.31 per share) for 2009. Included in our net income for 2011 was an after-tax gain from the sale of an investment in a limited partnership of $0.6 million ($0.01 per share). Net income also includes after-tax gains from the sale of assets of $8.8 million ($0.08 per share) in 2011, $3.3 million ($0.03 per share) in 2010 and $3.4 million ($0.03 per share) in 2009. Included in net income in 2009 is an after-tax gain of $0.3 million from involuntary conversion of 37 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. 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. Since April 1, 2009, the investment in Atwood has been recorded at fair value with changes included as a component of other comprehensive income. Consolidated operating revenues were $2,543.9 million in 2011, $1,875.2 million in 2010 and $1,843.7 million in 2009. In 2011 and 2010, customers increased spending for exploration and development drilling, recovering from the declines in oil and natural gas prices and uncertainties in the capital markets that existed in 2009. As a result, our U.S. land rig utilization was 86 percent in 2011, 73 percent in 2010 and 68 percent in 2009. The average number of U.S. land rigs available was 237 rigs in 2011, 207 rigs in 2010 and 194 rigs in 2009. Revenue in the Offshore segment remained steady in 2011, 2010 and 2009. Rig utilization for offshore rigs was 77 percent in 2011, compared to 80 percent in 2010 and 89 percent in 2009. Revenue in the International Land segment decreased in 2011, after increasing in 2010 from 2009, due to a decline in available rigs. Rig utilization in our International Land segment was 70 percent in 2011, 71 percent in 2010 and 70 percent in 2009. In 2011, we had a $0.9 million gain from the sale of investment securities. We did not sell any investment securities in 2010 or 2009. 38 Interest and dividend income was $2.0 million, $1.8 million and $2.8 million in 2011, 2010 and 2009, respectively. Direct operating costs in 2011 were $1,432.6 million or 56 percent of operating revenues, compared with $1,072.0 million or 57 percent of operating revenues in 2010 and $944.8 million or 51 percent of operating revenues in 2009. Depreciation expense was $315.5 million in 2011, $262.7 million in 2010 and $227.5 million in 2009. Included in depreciation are abandonments of equipment of $4.9 million in 2011, $4.2 million in 2010 and $5.3 million in 2009. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 36 new rigs in 2011, 23 in 2010 and 25 in 2009. Depreciation expense in 2012 is expected to increase from 2011 from new rigs placed into service during 2011 and additional rigs placed into service during 2012. (See Liquidity and Capital Resources.) As conditions warrant, management performs an analysis of the industry market conditions impacting its long-lived assets in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2011, 2010 and 2009, no impairment was recorded. General and administrative expenses totaled $91.5 million in 2011, $81.5 million in 2010 and $58.8 million in 2009. The $10.0 million increase in 2011 from 2010 is due to higher salaries and bonuses, primarily due to an increase in the number of employees, and increased benefit costs of approximately $7.3 million and an increase of $6.4 million primarily attributable to higher corporate overhead associated with supporting continuing growth of our drilling business. 39 These increases are partially offset by a decrease in our stock-based compensation expense of $3.7 million. In 2010, a change was made to our 2005 Long-Term Incentive Plan whereby amendments were made for continued vesting of restricted stock and stock options effective upon a participant becoming retirement eligible. As a result, additional compensation cost was incurred only in 2010. Interest expense was $17.4 million in 2011, $17.2 million in 2010 and $13.6 million in 2009. Interest expense is primarily attributable to the fixed-rate debt outstanding. Interest expense increased in 2011 from 2010 primarily due to increases in interest related to uncertain tax positions offset with an increase in capitalized interest. Capitalized interest was $8.2 million, $6.4 million and $6.6 million in 2011, 2010 and 2009, respectively. All of the capitalized interest is attributable to our rig construction program. The provision for income taxes totaled $252.4 million in 2011, $152.2 million in 2010 and $227.9 million in 2009. The effective income tax rate increased to 37 percent in 2011 from 35 percent in 2010 and decreased from 38 percent in 2009. 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 4 40 of the Consolidated Financial Statements for additional income tax disclosures.) During 2011, 2010 and 2009, we incurred $15.8 million, $12.3 million and $9.7 million, respectively, of research and development expenses related to ongoing development of the rotary steerable system tools. We anticipate research and development expenses to continue during 2012. Pursuant to the satisfaction of a performance milestone, we paid $4.0 million during the first fiscal quarter of 2011 that was accounted for as goodwill. The payment is shown as an investing activity in the Consolidated Statements of Cash Flows. In 2011, 2010 and 2009, we had a net loss from discontinued operations of $0.5 million, $129.8 million and $27.0 million, respectively. Our Venezuelan drilling business, including eleven rigs and associated real and personal property, was seized by the Venezuelan government on June 30, 2010. As a result, we derecognized our Venezuela property and equipment and warehouse inventory and wrote off our accounts receivable, payables and other deferred charges and credits as related future cash inflows and outflows associated with them were no longer expected to occur. Due to the inability of our Venezuelan subsidiary to obtain approval for a dividend to its U.S. based parent, we also impaired cash in an amount equivalent to the dividend request. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of 41 Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in two arbitrations against third parties not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $75 million relating to the seizure of our property in Venezuela. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements. The following tables summarize operations by reportable operating segment. 42 C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 1 a n d 2 0 1 0 U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2011 2010 % Change (in thousands, except operating statistics) $2,100,508 1,119,700 25,066 264,127 $ 691,615 73,905 25,809 12,538 13,271 $ $ $ 248 86% $1,412,495 772,766 23,799 211,652 $ 404,278 55,051 23,909 12,288 11,621 $ $ $ 220 73% 48.7% 44.9 5.3 24.8 71.1 34.2% 7.9 2.0 14.2 12.7 17.8 Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $193,093 and $96,304 for 2011 and 2010, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2010. Operating income in the U.S. Land segment increased to $691.6 million in 2011 from $404.3 million in 2010. Included in U.S. land revenues for 2011 and 2010 is approximately $5.4 million and $41.2 million, respectively, from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2011 increased by $2,574 to $25,735 from $23,161 in 2010, primarily attributable to increases in dayrates in 2011 compared to 2010. Direct operating expenses increased 44.9 percent in 2011 from 2010; however, the expense as a percentage of revenue decreased to 53 percent in 2011 from 55 percent in 2010. The average rig expense per day increased by only $250 during 2011. 43 Rig utilization increased to 86 percent in 2011 from 73 percent in 2010. The total number of rigs at September 30, 2011 was 248 compared to 220 rigs at September 30, 2010. The net increase is due to 35 new FlexRigs having been completed and placed into service, five transferred from the International Land segment, one transferred to the International Land segment, four sold and seven older mechanical highly mobile rigs removed from service. Subsequent to September 30, 2011, we sold two conventional rigs. Depreciation includes charges for abandoned equipment of $3.8 million and $3.5 million in 2011 and 2010, respectively. Excluding the abandonment amounts, depreciation in 2011 increased 25 percent from 2010 due to the increase in available rigs. We expect to complete and deliver approximately four rigs per month through the end of fiscal 2012. Like those completed in fiscal 2011, each of these new rigs is committed to work for an exploration and production company under a fixed multi-year term contract, performing drilling services on a daywork contract basis. As a result of the new FlexRigs added in fiscal 2011 and additional rigs scheduled for completion in fiscal 2012, we anticipate depreciation expense to continue to increase in fiscal 2012. At September 30, 2011, 224 out of 248 existing rigs in the U.S. Land segment were generating revenue. Of the 224 rigs generating revenue, 149 were under fixed-term contracts, and 75 were working in the spot market. At November 17, 2011, the number of existing rigs under fixed-term contracts in the segment was 147 and the number of rigs working in the spot market increased to 81. 44 C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 1 a n d 2 0 1 0 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 2011 2010 % Change (in thousands, except operating statistics) $201,417 135,368 6,074 14,684 $ 45,291 2,544 $ 51,794 $ 29,379 $ 22,415 9 77% $202,734 131,325 5,821 12,519 $ 53,069 2,642 $ 47,534 $ 24,653 $ 22,881 9 80% (0.6)% 3.1 4.3 17.3 (14.7) (3.7)% 9.0 19.2 (2.0) — (3.8) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $33,718 and $37,594 for 2011 and 2010, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in our Offshore segment declined by 14.7 percent in 2011 from 2010 primarily due to a decrease in revenue days. The decrease in revenue days is primarily due to the temporary stacking of a rig in early fiscal 2011 compared to the same rig working all of 2010. Our platform rig currently working offshore Trinidad is expected to complete its contract in the first quarter of fiscal 2012. The rig is expected to be shipped back to the U.S. and actively marketed. As a result, the segment could be negatively impacted after the first quarter of fiscal 2012. 45 C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 1 a n d 2 0 1 0 INTERNATIONAL LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2011 2010 % Change (in thousands, except operating statistics) $226,849 175,728 3,392 28,018 $ 19,711 6,406 $ 31,633 $ 23,416 $ 8,217 24 70% $247,179 166,021 2,949 29,938 $ 48,271 7,254 $ 32,451 $ 21,142 $ 11,309 28 71% (8.2)% 5.8 15.0 (6.4) (59.2) (11.7)% (2.5) 10.8 (27.3) (14.3) (1.4) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $24,207 and $11,779 for 2011 and 2010, respectively. Also excluded are the effects of currency revaluation expense. The International Land segment had operating income of $19.7 million for 2011 compared to $48.3 million for 2010. Rig utilization for International land operations decreased to 70 percent in 2011 from 71 percent in 2010. The total number of rigs at September 30, 2011 was 24 compared to 28 rigs at September 30, 2010. The decrease was due to five rigs transferred to the U.S. Land segment and one rig transferred from the U.S. Land segment. Segment operating income and average margin per day decreased in 2011 compared to 2010 primarily due to labor union interruptions in one country and idle rigs incurring fixed expenses. During the first quarter of fiscal 2012, a FlexRig will be transferred from the U.S. Land segment with operations expected to begin in the second fiscal quarter. 46 C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 0 a n d 2 0 0 9 2010 2009 % Change U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation (in thousands, except operating statistics) $1,412,495 $1,441,164 772,766 23,799 211,652 663,385 16,812 187,259 Segment operating income $ 404,278 $ 573,708 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 55,051 23,909 12,288 11,621 $ $ $ 220 73% 48,055 28,194 12,009 16,185 $ $ $ 201 68% (2.0)% 16.5 41.6 13.0 (29.5) 14.6% (15.2) 2.3 (28.2) 9.5 7.4 Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $96,304 and $86,297 for 2010 and 2009, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2010. Rig utilization excludes seven FlexRigs completed and ready for delivery at September 30, 2009. Operating income in the U.S. Land segment decreased to $404.3 million in 2010 from $573.7 million in 2009. Included in U.S. land revenues for 2010 and 2009 was approximately $41.2 million and $169.4 million, respectively, from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2010 decreased by $1,509 to $23,161 from $24,670 in 2009, as a result of lower average dayrates in 2010 compared to 2009. Direct operating expenses increased 17 percent in 2010 from 2009, and the expense as a percentage of revenue increased to 55 percent in 2010 from 46 percent in 2009. However, the average rig expense per day increased by only $279 during 2010, primarily as a result of costs incurred to reactivate idle rigs. 47 Rig utilization increased to 73 percent in 2010 from 68 percent in 2009. The total number of rigs at September 30, 2010 was 220 compared to 201 rigs at September 30, 2009. The net increase was due to 14 new FlexRigs completed and placed into service, one transferred to the International Land segment with a customer commitment, and six transferred from the International Land segment. Depreciation includes charges for abandoned equipment of $3.5 million and $4.9 million in 2010 and 2009, respectively. Excluding the abandonment amounts, depreciation in 2010 increased 14 percent from 2009 due to the increase in available rigs. C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 0 a n d 2 0 0 9 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 2010 2009 % Change (in thousands, except operating statistics) $202,734 131,325 5,821 12,519 $ 53,069 2,642 $ 47,534 $ 24,653 $ 22,881 9 80% $204,702 133,442 4,095 11,872 $ 55,293 2,938 $ 48,677 $ 27,373 $ 21,304 9 89% (1.0)% (1.6) 42.1 5.4 (4.0) (10.1)% (2.3) (9.9) 7.4 — (10.1) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $37,594 and $34,125 for 2010 and 2009, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in our Offshore segment decreased by four percent in 2010 from 2009 primarily due to reduced activity. Segment operating income was not significantly impacted during 48 2010 as a result of the government imposed deepwater drilling moratorium. C o m p a r i s o n o f t h e y e a r s e n d e d S e p t e m b e r 3 0 , 2 0 1 0 a n d 2 0 0 9 INTERNATIONAL LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2010 2009 % Change (in thousands, except operating statistics) $247,179 166,021 2,949 29,938 $ 48,271 7,254 $ 32,451 $ 21,142 $ 11,309 28 71% $187,099 146,565 2,301 19,278 $ 18,955 4,807 $ 35,618 $ 26,528 $ 9,090 33 70% 32.1% 13.3 28.2 55.3 154.7 50.9% (8.9) (20.3) 24.4 (15.2) 1.4 Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $11,779 and $15,884 for 2010 and 2009, 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. The International Land segment had operating income of $48.3 million for 2010 compared to $19.0 million for 2009, primarily due to an increase in revenue days. Rig utilization for International land operations increased to 71 percent in 2010 from 70 percent in 2009. The total number of rigs at September 30, 2010 was 28 compared to 33 rigs at September 30, 2009. The decrease was due to six rigs transferring to the U.S. Land segment and one rig transferring to the International Land segment. Five of the six rigs had been in the International Land segment for prospective bidding purposes and came back to the U.S. under contract. The rig transferred to the International Land segment 49 was in transit to a customer location at September 30, 2010. Two FlexRigs completed in 2009 and one FlexRig completed in 2008 were placed into service during 2010. Direct operating expenses increased primarily due to an increase in activity. However, the average rig expense per day decreased in 2010 from 2009 as revenue days increased and labor and stacking expenses related to rigs that became idle were reduced. 50 LIQUIDIT Y AND CAPITAL RESOURCES Our capital spending was $694.3 million in 2011, $329.6 million in 2010 and $876.8 million in 2009. Net cash provided from operating activities was $977.6 million in 2011, $462.3 million in 2010 and $895.9 million in 2009. Our 2012 capital spending level will be primarily driven by our new build construction program as it adapts to market demand for incremental FlexRigs during the year. Given the number of customer commitments that we already have for new FlexRigs to be completed in 2012, and the level of rig component orders that are required to ensure our ability to effectively respond to additional new FlexRig demand, our current capital spending estimate for 2012 is approximately $1.1 billion. 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. A $12.5 million short-term investment purchased in 2009 matured in 2010. We manage a portfolio of marketable securities that, at the close of fiscal 2011, had a fair value of $348.5 million. Our investments in Atwood and Schlumberger, Ltd. made up 95 percent of the portfolio’s fair value on September 30, 2011. 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. 51 We generated cash proceeds from the sale of an investment in a limited partnership of $3.9 million in 2011. We did not sell any portfolio securities in 2010 or 2009. Our proceeds from asset sales totaled $26.8 million in 2011, $7.9 million in 2010 and $8.1 million in 2009. Income from asset sales in 2011 totaled $13.9 million which includes the sale of four rigs. These four rigs were idle at the time of the sales and had been classified as held for sale in the Consolidated Balance Sheet. In each year we also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business. 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 6.53 percent. The terms of the debt obligations require that we maintain a minimum ratio of debt to total capitalization of less than 55 percent. We have $200 million senior unsecured fixed-rate notes that mature over a period from July 2012 to July 2016. Interest on the notes is 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 July 21, 2012. 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. 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 all of the borrowings have accrued interest at 52 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 2011 fiscal year, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. At September 30, 2011, we had two letters of credit totaling $21.9 million under the facility and had no borrowings with $378.1 million remaining available to borrow. Subsequent to September 30, 2011, we funded two collateral trusts and terminated both letters of credit. Financial covenants in the facility 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. The Company does not anticipate that it will require additional financing in the near future and therefore the $400 million senior unsecured facility may be allowed to expire at maturity. The applicable agreements for all of the unsecured debt described above 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, 2011, we were in compliance with all debt covenants. At September 30, 2011, we had 158 existing rigs with contracts under fixed terms with original term durations ranging from six months to seven years, with some expiring in fiscal 2012. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is 53 terminated prior to the expiration of the fixed term. 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 could be negatively impacted if this were to happen. Our operating cash requirements, scheduled debt repayments and estimated capital expenditures, including our rig construction program, for fiscal 2012 is expected to be funded through current cash, cash provided from operating activities, funds available under any new credit facility and, possibly, sales of available-for-sale securities. The current ratio was 2.3 at September 30, 2011 and 2.9 at September 30, 2010. The long-term debt to total capitalization ratio, including the current portion of long-term debt, was 10 percent at September 30, 2011 compared to 11 percent at September 30, 2010. During 2011, we paid dividends of $0.25 per share, or a total of $26.7 million, representing the 39th consecutive year of dividend increases. STOCK PORTFOLIO HELD September 30, 2011 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 $274,880 7,685 9,350 57,789 15,817 $138,533 $348,486 54 Material Commitments We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2011, are summarized in the table below in thousands: Payments due by year Contractual Obligations Total 2012 2013 2014 2015 2016 After 2016 Long-term debt and estimated interest (a) $403,431 $136,291 $54,206 $126,563 $44,405 $41,966 Operating leases (b) 23,853 5,979 Purchase obligations (b) 361,290 361,290 4,557 — 2,524 — 2,343 — 1,961 — $ — 6,489 — Total contractual obligations $788,574 $503,560 $58,763 $129,087 $46,748 $43,927 $6,489 (a) Interest on fixed-rate debt was estimated based on principal maturities. See Note 3 ‘‘Debt’’ to our Consolidated Financial Statements. (b) See Note 14 ‘‘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 2011, we contributed $11.3 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $0.8 million in 2012 to meet the minimum contribution required by law. We expect to make additional contributions in 2012 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond 2012 are difficult to estimate due to multiple variables involved. At September 30, 2011, we had $12.3 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 4 to the Consolidated Financial Statements. 55 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 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 56 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 upon estimated discounted future cash flows or estimated fair market value, if available. 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 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 57 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 which is 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 (‘‘ASC’’) 820. (See Note 8 of the Consolidated Financial Statements for fair value 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 outside or inside of the United States. 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. Nonetheless, insurance estimates include certain assumptions and 58 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 and a stop-loss on our self-insured health plan. 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 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 seven offshore platform rigs for ‘‘named windstorm’’ risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million aggregate insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers three rigs and has a $40 million aggregate 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 coverage amounts 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 59 development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense and related liabilities. We self insure a number of other risks including loss of earnings and business interruption. 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 4.48 percent to 4.33 percent as of September 30, 2011 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 to be approximately $2.7 million in 2012 which is comparable to 2011. 60 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 the 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 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 determined based on the average of the high and low 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, 2011, unrecognized compensation cost related to unvested restricted stock was $7.9 million. The cost is expected to be recognized over a weighted-average period of 2.2 years. 61 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 On October 1, 2010, we adopted Accounting Standards Update (‘‘ASU’’) No. 2009-13, Multiple-Deliverable Revenue Arrangements—a consensus of the FASB Emerging Issues Task Force (Topic 605), which amended the revenue guidance under ASC 605. The adoption had no impact on our Consolidated Financial Statements. On September 15, 2011, the Financial Accounting Standards Board (‘‘FASB’’) issued ASU No. 2011-08, Intangibles—Goodwill and Other (ASC Topic 350): Testing Goodwill for Impairment. ASU No. 2011-08 modifies the impairment test for goodwill and indefinite lived intangibles so that it is no longer required to calculate the fair value of a reporting unit unless the Company believes, based on qualitative factors, it is more likely than not that the reporting unit’s or indefinite lived intangible asset’s fair value is less than the carrying value. ASU No. 2011-08 is effective for fiscal years that begin after December 15, 2011, with early adoption allowed. We elected to early 62 adopt ASU No. 2011-08 effective September 15, 2011, with no impact on the Consolidated Financial Statements. On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements. The disclosure requirements requiring reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy were adopted on December 15, 2009 with no impact on the Consolidated Financial Statements. Effective for fiscal years beginning after December 15, 2010, a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments, will be required. We currently believe the adoption related to Level 3 financial instruments will have no impact on the Consolidated Financial Statements. On May 12, 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU No. 2011-04 is intended to create consistency between U.S. GAAP and International Financial Reporting Standards (‘‘IFRS’’) on the definition of fair value and on the guidance on how to measure fair value and on what to disclose about fair value measurements. ASU No. 2011-04 will be effective for financial statements issued for fiscal periods beginning after December 15, 2011, with early adoption prohibited for public entities. We do not expect the adoption of these provisions to have a material impact on the Consolidated Financial Statements. 63 On June 16, 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU No. 2011-05 was issued to increase the prominence of other comprehensive income (‘‘OCI’’) in financial statements. The guidance provides two options for presenting OCI. An OCI statement can be included with the net income statement, which together will make a statement of total comprehensive income. Alternatively, an OCI statement can be separate from a net income statement but the two statements will have to appear consecutively within a financial report. ASU No. 2011-05 will be applied retrospectively and is effective for fiscal periods beginning after December 15, 2011 with early adoption permitted. We are currently evaluating the method of presentation and the timing of adoption but the adoption will have no impact on the Consolidated Financial Statements. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Foreign Currency Exchange Rate Risk We have operations in several South American countries, Trinidad, Africa and the Middle East. With the exception of Argentina, 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 2009, resulting in the recording of a $2.2 million currency loss. In 2010, a devaluation loss of $0.8 million was recorded from a 2.6 percent devaluation of the Argentine peso to the U.S. dollar. In 2011, a devaluation loss of $0.4 million was recorded from a 6.3 percent devaluation of the Argentine peso to the U.S. dollar. 64 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. All of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities 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. 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 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. Any deterioration in the credit and capital 65 markets, as experienced in 2008 and 2009, can make it 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 results 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 have a material adverse effect on future operating costs. Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. Because all of our debt at September 30, 2011 has fixed-rate interest obligations, there is no current risk due to interest rate fluctuation. The following tables provide information as of September 30, 2011 and 2010 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 1 1 (dollars in thousands) 2012 2013 2014 2015 2016 After 2016 Total Fair Value 9/30/11 Fixed-Rate Debt $115,000 $40,000 $115,000 $40,000 $40,000 $— $350,000 $376,882 Average Interest Rate 6.4% 6.1% 6.5% 6.1% 6.1% —% 6.3% Variable Rate Debt $ — $ — $ — $ — $ — $— $ — $ — Average Interest Rate 66 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 1 0 (dollars in thousands) Fixed-Rate Debt Average Interest Rate Variable Rate Debt $ $ Average Interest Rate (a) 2011 2012 2013 2014 2015 After 2015 Total Fair Value 9/30/10 — $115,000 $40,000 $115,000 $40,000 $40,000 $350,000 $382,852 — 6.4% 6.1% 6.5% 6.1% 6.1% 6.3% — $ 10,000 $ — $ — $ — $ — $ 10,000 $ 10,000 (a) (a) Advances bear interest rate of .61% Equity Price Risk On September 30, 2011, we had a portfolio of securities with a total fair value of $348.5 million. The total fair value of the portfolio of securities was $325.7 million at September 30, 2010. Our investments in Atwood and Schlumberger, Ltd. made up 95 percent of the portfolio’s fair value at September 30, 2011. 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 17, 2011, the total fair value of the portfolio of securities had increased to approximately $431.2 million with an estimated after-tax value of $278.3 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. 67 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders Helmerich & Payne, Inc. We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2011 and 2010, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2011, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne Inc.’s internal control over financial reporting as of September 30, 2011, 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 23, 2011 expressed an unqualified opinion thereon. / s / E R N S T & Y O U N G L L P Tulsa, Oklahoma November 23, 2011 68 Consolidated Statements of Income Years Ended September 30, OPERATING REVENUES Drilling – U.S. Land Drilling – Offshore Drilling – International Land Other OPERATING COSTS AND EXPENSES Operating costs, excluding depreciation Depreciation Research and development General and administrative Gain from involuntary conversion of long-lived assets Income from asset sales 2011 2010 2009 (in thousands, except per share amounts) $2,100,508 $1,412,495 $1,441,164 201,417 226,849 15,120 2,543,894 202,734 247,179 12,754 1,875,162 204,702 187,099 10,775 1,843,740 1,432,602 1,071,959 315,468 15,764 91,452 — 262,658 12,262 81,479 — 944,780 227,535 9,671 58,822 (541) (13,903) 1,841,383 (4,992) 1,423,366 (5,402) 1,234,865 Operating income from continuing operations 702,511 451,796 608,875 Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Income from continuing operations before income taxes and equity in income of affiliate Income tax provision Equity in income of affiliate net of income taxes Income from continuing operations Loss from discontinued operations before income taxes Income tax provision (benefit) Loss from discontinued operations NET INCOME Basic earnings per common share: Income from continuing operations Loss from discontinued operations Net income Diluted earnings per common share: Income from continuing operations Loss from discontinued operations Net income Weighted average shares outstanding (in thousands): Basic Diluted The accompanying notes are an integral part of these statements. 69 1,951 (17,355) 913 (953) 1,811 (17,158) — 1,787 2,755 (13,590) — 245 (15,444) (13,560) (10,590) 687,067 252,399 — 434,668 (487) (5) (482) 438,236 152,155 — 286,081 (125,944) 3,825 (129,769) 598,285 227,850 10,111 380,546 (22,470) 4,531 (27,001) $ 434,186 $ 156,312 $ 353,545 $ $ $ $ $ $ 4.06 $ — $ 4.06 $ 3.99 $ — $ 3.99 $ $ 2.70 (1.23) $ 1.47 $ $ 2.66 (1.21) $ 1.45 $ 3.61 (0.26) 3.35 3.56 (0.25) 3.31 106,643 108,632 105,711 107,404 105,364 106,608 Consolidated Balance Sheets ASSETS CURRENT ASSETS: September 30, 2011 2010 (in thousands) Cash and cash equivalents $ 364,246 $ 63,020 Accounts receivable, less reserve of $776 in 2011 and $830 in 2010 Inventories Deferred income taxes Prepaid expenses and other Current assets of discontinued operations Total current assets 460,540 54,407 19,855 49,736 7,529 956,313 457,659 43,402 14,282 64,171 10,270 652,804 INVESTMENTS 347,924 320,712 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment Construction in progress Real estate properties Other Less – Accumulated depreciation Net property, plant and equipment NONCURRENT ASSETS: Other assets TOTAL ASSETS The accompanying notes are an integral part of these statements. 4,834,985 4,285,277 232,703 61,476 211,897 5,341,061 1,663,991 3,677,070 154,595 61,735 182,087 4,683,694 1,408,674 3,275,020 22,584 16,834 $5,003,891 $4,265,370 70 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, CURRENT LIABILITIES: Accounts payable Accrued liabilities Long-term debt due within one year Current liabilities of discontinued operations Total current liabilities NONCURRENT LIABILITIES: Long-term debt Deferred income taxes Other Noncurrent liabilities of discontinued operations Total noncurrent liabilities SHAREHOLDERS’ EQUITY: 2011 2010 (in thousands, except share data and per share amounts) $ 103,852 $ 80,534 192,898 115,000 4,979 416,729 235,000 975,280 104,285 2,550 144,112 — 7,992 232,638 360,000 771,383 91,606 2,278 1,317,115 1,225,267 Common stock, $.10 par value, 160,000,000 shares authorized, 107,243,473 and 107,057,904 shares issued as of September 30, 2011 and 2010, respectively and 107,086,324 and 105,819,161 shares outstanding as of September 30, 2011 and 2010, 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, 157,149 shares in 2011 and 1,238,743 shares in 2010, at cost Total shareholders’ equity 10,724 — 210,909 2,954,210 98,908 3,274,751 4,704 3,270,047 10,706 — 191,900 2,547,917 84,107 2,834,630 27,165 2,807,465 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,003,891 $4,265,370 The accompanying notes are an integral part of these statements. 71 Consolidated Statements of Shareholders’ Equity Common Stock Shares Amount Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Shares Treasury Stock Amount Total Balance, September 30, 2008 Comprehensive Income: Net income Other comprehensive loss: Unrealized gains on available-for-sale securities, net Amortization of net periodic benefit costs – net of actuarial gain Total other comprehensive gain Total comprehensive income Capital adjustment of equity investee Dividends declared ($.20 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $1.2 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September 30, 2009 Comprehensive Income: Net income Other comprehensive loss: Unrealized losses on available-for-sale securities, net Amortization of net periodic benefit costs – net of actuarial gain Total other comprehensive loss Total comprehensive income Dividends declared ($.22 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $3.9 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September 30, 2010 Comprehensive Income: Net income Other comprehensive income (loss): Unrealized gains on available-for-sale securities, net Amortization of net periodic benefit costs – net of actuarial gain Total other comprehensive income Total comprehensive income Dividends declared ($.26 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $13.4 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September 30, 2011 107,058 $10,706 $169,497 $2,082,518 $ 38,407 1,835 $(35,654) $2,265,474 (in thousands, except share and per share amounts) 353,545 88,519 (14,475) (21,121) (197) 3,250 353,545 88,519 (14,475) 74,044 427,589 174 (21,121) 1,272 (66) 2,414,942 112,451 1,572 1,275 1,273 — 8,348 (31,129) 2,683,009 156,312 (22,885) (5,459) (23,337) (263) 2,519 156,312 (22,885) (5,459) (28,344) 127,968 (23,337) (202) (70) 2,547,917 84,107 1,239 1,445 4,172 — 15,855 (27,165) 2,807,465 174 (1,978) 1,273 (1,275) 8,348 176,039 (2,721) 4,172 (1,445) 15,855 191,900 107,058 10,706 107,058 10,706 434,186 (27,893) 18,414 (3,613) 185 18 (3,942) (948) 19,365 434,186 18,414 (3,613) 14,801 448,987 (27,893) 15,441 13,946 (3,096) 12,101 107,243 $10,724 $210,909 $2,954,210 $ 98,908 (134) 13,946 — 12,101 157 $ (4,704) $3,270,047 3,096 The accompanying notes are an integral part of these statements. 72 Consolidated Statements of Cash Flows Years Ended September 30, 2011 2010 2009 OPERATING ACTIVITIES: Net income Adjustment for loss from discontinued operations Income from continuing operations 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 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 from continuing operations Net cash provided by (used in) operating activities from discontinued operations Net cash provided by operating activities INVESTING ACTIVITIES: Capital expenditures Acquisition of TerraVici Drilling Solutions 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 from continuing operations Net cash used in investing activities from discontinued operations Net cash used in investing activities FINANCING ACTIVITIES: 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 Exercise of stock options Excess tax benefit from stock-based compensation Net cash provided by (used in) financing activities $ 434,186 482 434,668 (in thousands) $ 156,312 129,769 286,081 $ 353,545 27,001 380,546 315,468 106 — 12,101 (913) — (13,903) 187,651 — (2,987) (11,005) 12,623 17,362 20,483 251 6,129 978,034 (482) 977,552 (694,264) (4,000) 26,795 — — 3,932 (667,537) — (667,537) — — 10,000 (20,000) — (26,741) 15,441 12,511 (8,789) 262,658 206 — 15,855 — — (4,992) 105,691 79 (223,916) (3,858) (12,800) 16,760 14,031 2,453 8,402 466,650 (4,362) 462,288 (329,572) — 7,867 — (16) 12,516 (309,205) (55) (309,260) 227,535 (645) (16,308) 8,348 — (541) (5,402) 158,153 (244) 156,863 (10,981) (9,442) (24,996) 2,672 8,234 (1,525) 872,267 23,672 895,939 (876,839) (16) 8,069 541 (12,500) — (880,745) (3,284) (884,029) — — 895,000 (1,060,000) (2,038) (22,254) (202) 3,344 (186,150) (1,733) (25,000) 3,840,000 (3,790,000) 2,038 (21,111) 1,272 1,217 6,683 Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period 301,226 63,020 364,246 $ (33,122) 96,142 63,020 $ 18,593 77,549 96,142 $ The accompanying notes are an integral part of these statements. 73 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. BASIS OF PRESENTATION We classified the Venezuelan operation, an operating segment within the International Land segment, as a discontinued operation in the third quarter of fiscal 2010, as more fully described in Note 2. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates only to our continuing operations. FOREIGN CURRENCIES The functional currency for all our foreign operations 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 $1.2 million, $0.5 million and $3.0 million in fiscal 2011, 2010 and 2009, respectively. 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 STANDARDS On October 1, 2010, we adopted Accounting Standards Update (‘‘ASU’’) No. 2009-13, Multiple-Deliverable Revenue Arrangements—a consensus of the FASB Emerging Issues Task Force (Topic 605), which amended the revenue guidance under Accounting Standards Codification (‘‘ASC’’) 605. The adoption had no impact on the Consolidated Financial Statements. On September 15, 2011, the Financial Accounting Standards Board (‘‘FASB’’) issued ASU No. 2011-08, Intangibles—Goodwill and Other (ASC Topic 350): Testing Goodwill for Impairment. ASU No. 2011-08 modifies the impairment test for goodwill and indefinite lived intangibles so that it is no longer required to calculate the fair value of a reporting unit unless the Company believes, based on qualitative factors, it is more likely than not that the reporting unit’s or indefinite lived intangible asset’s fair value is less than the carrying value. ASU No. 2011-08 is effective for fiscal years that begin after December 15, 2011, with early adoption allowed. We 74 elected to early adopt ASU No. 2011-08 effective September 15, 2011, with no impact on the Consolidated Financial Statements. 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, and several ‘‘zero-balance’’ disbursement accounts for funding 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 $18.0 million and $14.8 million at September 30, 2011 and 2010, 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, 2011, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $16.0 million. 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: September 30, Other current assets Other assets 2011 2010 (in thousands) $16,015 $ 2,000 $12,848 $ 2,000 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 75 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. 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 $4.9 million, $4.2 million and $5.3 million for fiscal 2011, 2010 and 2009, respectively. The cost of maintenance and repairs is charged to direct operating cost, while betterments and refurbishments are capitalized. During the quarter ended September 30, 2011, we made a decision to reclassify two land rigs in the U.S. Land segment previously presented as assets held for sale during fiscal 2011 to property and equipment, due to our intention to utilize such equipment in operations. A third land rig previously presented as held for sale during fiscal 2011 was sold during the fourth quarter. Effective September 30, 2011, we decommissioned seven idle mechanical highly mobile rigs. 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 2011, 2010 and 2009 was $8.2 million, $6.4 million and $6.6 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. 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 down to the estimated fair value of the asset. The fair value of drilling rigs is determined based upon estimated discounted future cash flows or estimated fair market value, if available. 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 make up to existing platforms, and competitive dynamics due to lower industry utilization. 76 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. Reimbursements for fiscal 2011, 2010 and 2009 were $251.0 million, $145.7 million and $136.3 million, respectively. 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 generally 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 2011 $8,941 $1,135 2010 (in thousands) $8,613 $1,241 2009 $8,803 $1,414 At September 30, 2011, minimum future rental income to be received on noncancelable operating leases was as follows: Fiscal Year 2012 2013 2014 2015 2016 Thereafter Total Amount (in thousands) $ 7,156 5,706 4,712 3,696 2,535 7,698 $31,503 77 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2011 and 2010, the cost and accumulated depreciation for real estate properties were as follows: September 30, Real estate properties Accumulated depreciation 2011 2010 (in thousands) $61,476 (39,665) $21,811 $61,735 (39,030) $22,705 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, Income Taxes, which was adopted effective October 1, 2007, and is more fully discussed in Note 4. 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 Consolidated Statements of Income. EARNINGS PER SHARE Basic earnings per share is computed utilizing the two-class method and is calculated based on weighted- average number of common shares outstanding during the periods presented. Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and nonvested 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. 78 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 On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements. The disclosure requirements requiring reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy were adopted on December 15, 2009 with no impact on the Consolidated Financial Statements. Effective for fiscal years beginning after December 15, 2010, a reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments, will be required. We currently believe the adoption related to Level 3 financial instruments will have no impact on the Consolidated Financial Statements. On May 12, 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU No. 2011-04 is intended to create consistency between U.S. GAAP and International Financial Reporting Standards (‘‘IFRS’’) on the definition of fair value and on the guidance on how to measure fair value and on what to disclose about fair value measurements. ASU No. 2011-04 will be effective for financial statements issued for fiscal periods beginning after December 15, 2011, with early adoption prohibited for public entities. We do not expect the adoption of these provisions to have a material impact on the Consolidated Financial Statements. On June 16, 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU No. 2011-05 was issued to increase the prominence of other comprehensive income (‘‘OCI’’) in financial statements. The guidance provides two options for presenting OCI. An OCI statement can be included with the net income statement, which together will make a statement of total comprehensive income. Alternatively, an OCI statement can be separate from a net income statement but the two statements will have to appear consecutively within a financial report. ASU No. 2011-05 will be applied retrospectively and is effective for fiscal periods beginning after December 15, 2011 with early adoption permitted. We are currently evaluating the method of presentation and the timing of adoption but the adoption will have no impact on the Consolidated Financial Statements. NOTE 2 DISCONTINUED OPERATIONS On June 30, 2010, the Official Gazette of Venezuela published the Decree of Venezuelan President Hugo Chavez, which authorized the ‘‘forceful acquisition’’ of eleven rigs owned by our Venezuelan subsidiary. The Decree also authorized the seizure of ‘‘all the personal and real property and other improvements’’ used by our Venezuelan subsidiary in its drilling operations. The seizing of our assets became effective June 30, 2010, and met the criteria established for recognition as discontinued operations under accounting standards for presentation of financial statements. Therefore, operations from the Venezuelan subsidiary, an operating 79 segment within the International Land segment, have been classified as discontinued operations in our Consolidated Financial Statements. As a result of the seizing of our assets in the third quarter of fiscal 2010, we derecognized our Venezuela property and equipment and warehouse inventory and wrote off our accounts receivable, payables and other deferred charges and credits as related future cash inflows and outflows associated with them were no longer expected to occur. Due to the inability of our Venezuelan subsidiary to obtain approval for a dividend to its U.S. based parent, we also impaired cash in an amount equivalent to the dividend request. The remaining cash was classified as restricted cash, a current asset from discontinued operations, to meet remaining in-country current obligations. Summarized operating results from discontinued operations are as follows: Years Ended September 30, Revenue Loss before income taxes Income tax provision (benefit) Loss from discontinued operations 2011 $ — (487) (5) $ (482) 2010 (in thousands) $ 13,534 (125,944) 3,825 $(129,769) Significant categories of assets and liabilities from discontinued operations are as follows: September 30, Other current assets Total assets Total current liabilities Total noncurrent liabilities Total liabilities (in thousands) 2011 $7,529 $7,529 $4,979 2,550 $7,529 2009 $ 50,298 (22,470) 4,531 $(27,001) 2010 $10,270 $10,270 $ 7,992 2,278 $10,270 Liabilities consist of municipal and income taxes payable and social obligations due within the country of Venezuela. 80 NOTE 3 DEBT At September 30, 2011 and 2010, we had $235 million and $360 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table: Unsecured intermediate debt issued August 15, 2002: 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, .61% Less long-term debt due within one year Long-term debt September 30, 2011 2010 (in thousands) $ 75,000 75,000 40,000 40,000 40,000 40,000 40,000 — $350,000 115,000 $235,000 $ 75,000 75,000 40,000 40,000 40,000 40,000 40,000 10,000 $360,000 — $360,000 The intermediate unsecured debt outstanding at September 30, 2011 matures over a period from August 2012 to August 2014 and carries a weighted-average interest rate of 6.53 percent, which is paid semi-annually. The terms require that we maintain a minimum ratio of debt to total capitalization of less than 55 percent. The debt is held by various entities, including $3 million held by a company affiliated with one of our Board members. We have $200 million senior unsecured fixed-rate notes that mature over a period from July 2012 to July 2016. Interest on the notes is 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 July 21, 2012. Financial covenants require us to 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. 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, all the borrowings over the life of the facility have accrued 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, 2011, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. At September 30, 2011, we had two letters of credit totaling $21.9 million under the facility and no borrowings against the facility leaving $378.1 million available to borrow. Subsequent to 81 September 30, 2011, we funded two collateral trusts and terminated both letters of credit. Financial covenants in the facility require 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. We do not anticipate that we will require additional financing in the near future and therefore the $400 million senior unsecured facility may be allowed to expire at maturity. The applicable agreements for all unsecured debt described in this Note 3 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, 2011, we were in compliance with all debt covenants. At September 30, 2011, aggregate maturities of long-term debt are as follows (in thousands): Years ending September 30, 2012 2013 2014 2015 2016 NOTE 4 INCOME TAXES $115,000 40,000 115,000 40,000 40,000 $350,000 The components of the provision for income taxes are as follows: Years Ended September 30, 2011 2010 (in thousands) 2009 Current: Federal Foreign State Deferred: Federal Foreign State Total provision $ 42,377 $ 31,312 $ 45,780 14,259 8,112 64,748 185,076 (4,117) 6,692 187,651 $252,399 13,215 1,937 46,464 100,206 7,846 (2,361) 105,691 $152,155 13,442 8,889 68,111 148,367 2,865 8,507 159,739 $227,850 82 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 2011 $666,073 20,994 $687,067 2010 (in thousands) $389,383 48,853 $438,236 2009 $571,028 27,257 $598,285 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. The components of our net deferred tax liabilities are as follows: September 30, Deferred tax liabilities: Property, plant and equipment Available-for-sale securities 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 2011 2010 (in thousands) $ 898,657 119,464 62 1,018,183 14,260 8,344 54,967 36,672 3,224 117,467 54,709 62,758 $703,404 107,917 136 811,457 15,549 4,249 45,343 31,102 3,456 99,699 45,343 54,356 $ 955,425 $757,101 The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2011, we had state and foreign net operating loss carryforwards for income tax purposes of $10.3 million and $29.0 million, respectively, and foreign tax credit carryforwards of approximately $47.0 million (of which $44.0 million is reflected as a deferred tax asset in our Consolidated Financial Statements prior to consideration of our valuation allowance) which will expire in years 2012 through 83 2021. 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, U.S. Federal income tax rate Effect of foreign taxes State income taxes Effective income tax rate 2011 35% 1 1 37% 2010 35% 1 (1) 35% 2009 35% 1 2 38% 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, 2011 and 2010, we had accrued interest and penalties of $5.4 million and $3.2 million, respectively. A reconciliation of the change in our gross unrecognized tax benefits for the fiscal year ended September 30, 2011 and 2010 is as follows: September 30, Unrecognized tax benefits at October 1, Gross decreases – tax positions in prior periods Gross increases – tax positions in prior periods Gross increases – current period effect of tax positions Expiration of statute of limitations for assessments Unrecognized tax benefits at September 30 2011 2010 (in thousands) $ 5,549 $5,244 (249) 2,561 434 (1,417) — 177 128 — $ 6,878 $5,549 As of September 30, 2011 and September 30, 2010, our liability for unrecognized tax benefits was $6.9 million and $5.6 million, respectively, which would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets. 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. 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 2007 through 2010. Audits in foreign jurisdictions are generally complete through fiscal year 1999. 84 NOTE 5 SHAREHOLDERS’ EQUITY On September 30, 2011, we had 107,086,324 outstanding preferred 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 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 that event, each holder of a Right (other than the acquiring person) shall have the right to receive, upon exercise of the Right, common stock of the Company having a value equal to two times the exercise price of the Right. 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 6 STOCK-BASED COMPENSATION In March 2006, the Company adopted the 2005 Long-Term Incentive Plan (the ‘‘2005 Plan’’) providing for common-stock based awards to employees and to non-employee Directors. The 2005 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. As of December 7, 2010, there were 324,162 nonqualified stock options and 169,375 shares of restricted stock awards granted under the 2005 Plan. Effective March 2, 2011, no further common-stock based awards will be made under the 2005 Plan. However, awards outstanding in the 2005 Plan and one prior equity plan remain subject to the terms and conditions of those plans. On December 1, 2009, we amended the forms of agreement under the plan for awards of nonqualified stock options, incentive stock options and restricted stock. We also amended existing stock option and restricted stock award agreements. The amendments provide for continued vesting (and accelerated vesting upon death) of restricted stock and stock options effective upon a participant becoming retirement eligible. A participant meets the definition of retirement eligible if the participant attains age 55 and has 15 or more years of continuous service as a full-time employee. The amendments apply retroactively. As a result of the continued vesting provisions, we incurred additional compensation cost of approximately $4.9 million in fiscal 2010. 85 On March 2, 2011, the 2010 Long-Term Incentive Plan (the ‘‘2010 Plan’’) was approved by our stockholders. The 2010 Plan, among other things, authorizes the Board of Directors to grant nonqualified stock options, restricted stock awards and stock appreciation rights to selected employees and to non-employee Directors. As of September 30, 2011, no awards have been made from the 2010 Plan. A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal 2011, 2010 and 2009 is as follows: September 30, Compensation expense Stock options Restricted stock 2011 $ 7,224 4,877 $12,101 2010 (in thousands) $11,475 4,380 $15,855 2009 $6,899 1,449 $8,348 Benefits of tax deductions in excess of recognized compensation cost of $12.5 million, $3.3 million and $1.2 million are reported as a financing cash flow in the Consolidated Statements of Cash Flows for fiscal 2011, 2010 and 2009, 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 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) 2011 1.9% 51.6% 0.5% 5.5 2010 2.3% 49.9% 0.5% 5.8 2009 1.7% 43.3% 0.9% 5.8 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. 86 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 $22.20, $17.64 and $8.16 per share for fiscal 2011, 2010 and 2009, respectively. The following summary reflects the stock option activity for our common stock and related information for fiscal 2011, 2010 and 2009 (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2011 2010 2009 Weighted-Average Exercise Price $22.82 47.94 18.24 34.06 $25.84 $22.35 Options 5,572 324 (1,289) (18) 4,589 3,287 6,000 Weighted-Average Exercise Price $20.55 38.02 13.63 38.02 $22.82 $19.68 Options 5,401 570 (397) (2) 5,572 3,888 761 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 The following table summarizes information about stock options at September 30, 2011 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $11.3318 to $16.01 $21.05 to $30.2375 $35.105 to $47.935 $11.3318 to $47.935 Options 1,489 1,641 1,459 4,589 Weighted-Average Remaining Life Weighted-Average Exercise Price 2.1 5.9 7.6 5.2 $13.91 $24.97 $38.99 $25.84 Options 1,489 1,230 568 3,287 Weighted-Average Exercise Price $13.91 $26.27 $36.00 $22.35 At September 30, 2011, the weighted-average remaining life of exercisable stock options was 4.1 years and the aggregate intrinsic value was $60.1 million with a weighted-average exercise price of $22.35 per share. The number of options vested or expected to vest at September 30, 2011 was 4,467,093 with an aggregate intrinsic value of $69.0 million and a weighted-average exercise price of $25.67 per share. As of September 30, 2011, the unrecognized compensation cost related to the stock options was $9.7 million. That cost is expected to be recognized over a weighted-average period of 2.5 years. 87 The total intrinsic value of options exercised during fiscal 2011, 2010 and 2009 was $50.5 million, $11.3 million and $4.9 million, respectively. The grant date fair value of shares vested during fiscal 2011, 2010 and 2009 was $7.9 million, $7.0 million and $6.3 million, respectively. RESTRICTED STOCK Restricted stock awards consist of our common stock and are time vested over three to six 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 average of the high and low price of our shares on the grant date. As of September 30, 2011, there was $7.9 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 2.2 years. A summary of the status of our restricted stock awards as of September 30, 2011, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2011, 2010 and 2009, is as follows (share amounts in thousands): Outstanding at October 1, Granted Vested Forfeited/Expired Outstanding on September 30, 2011 Weighted-Average Grant Date Fair Value per Share $35.23 47.94 33.92 47.94 Shares 289 169 (134) (1) 323 $42.38 2010 Weighted-Average Grant Date Fair Value per Share $30.06 38.02 29.36 — $35.23 Shares 177 182 (70) — 289 2009 Weighted-Average Grant Date Fair Value per Share $29.92 — 29.52 — $30.06 Shares 243 — (66) — 177 NOTE 7 EARNINGS PER SHARE ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant restricted stock grants to employees that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Basic earnings per share is computed utilizing the two-class method and is calculated based on weighted- average number of common shares outstanding during the periods presented. 88 Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and nonvested restricted stock. The following table sets forth the computation of basic and diluted earnings per share: September 30, Numerator: Income from continuing operations Loss from discontinued operations Net income Adjustment for basic earnings per share 2011 $434,668 (482) 434,186 2010 (in thousands) $286,081 (129,769) 156,312 2009 $380,546 (27,001) 353,545 Earnings allocated to unvested shareholders (1,295) (404) (617) Numerator for basic earnings per share: From continuing operations From discontinued operations Adjustment for diluted earnings per share: Effect of reallocating undistributed earnings of unvested shareholders Numerator for diluted earnings per share: From continuing operations From discontinued operations Denominator: Denominator for basic earnings per share – weighted-average shares Effect of dilutive shares from stock options and restricted stock Denominator for diluted earnings per share – adjusted weighted-average shares Basic earnings per common shares: Income from continuing operations Loss from discontinued operations Net income Diluted earnings per common shares: Income from continuing operations Loss from discontinued operations Net income 433,373 (482) 432,891 285,677 (129,769) 155,908 379,929 (27,001) 352,928 22 6 6 433,395 (482) $432,913 285,683 (129,769) $155,914 379,935 (27,001) $352,934 106,643 105,711 105,364 1,989 1,693 1,244 108,632 107,404 106,608 $ $ $ $ 4.06 — 4.06 3.99 — 3.99 $ $ $ $ 2.70 (1.23) 1.47 2.66 (1.21) 1.45 $ $ $ $ 3.61 (0.26) 3.35 3.56 (0.25) 3.31 89 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 2011 2010 2009 (in thousands, except per share amounts) 310 $47.94 554 $38.02 1,206 $33.12 NOTE 8 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 investments in limited partnerships carried at cost and assets held in a Non-qualified Supplemental Savings Plan: Equity Securities: September 30, 2011 September 30, 2010 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $129,183 $129,183 $203,486 $174,025 $— $— $332,669 $303,208 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. The investments in the limited partnerships carried at cost were approximately $9.4 million and $12.4 million at September 30, 2011 and 2010, respectively. The estimated fair value of the limited partnerships was $15.8 million and $22.5 million at September 30, 2011 and 2010, respectively. During fiscal 2011, we sold our investment in a limited partnership that was carried at a cost of approximately $3.0 million and had a fair value of approximately $3.9 million at the date of the sale. A gross realized gain of approximately $0.9 million is included in the Consolidated Statements of Income. The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $5.9 million and $5.1 million at September 30, 2011 and 2010, 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. 90 At September 30, 2009, our short-term investments consisted of a bank certificate of deposit with an original maturity greater than three months. The certificate matured in the second quarter of fiscal 2010. Interest earned is included in interest and dividend income on the Consolidated Statements of Income. The carrying amount of the certificate of deposit approximated fair value. The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2011 and 2010. ASC 820 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’’. ASC 820 establishes a fair value hierarchy to prioritize the inputs used in valuation techniques into three levels as follows: • Level 1 – Observable inputs that reflect quoted prices in active markets for identical assets or liabilities in active markets. • 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. • Level 3 – Valuations based on inputs that are unobservable and not corroborated by market data. At September 30, 2011, our financial assets utilizing Level 1 inputs include cash equivalents, equity securities with active markets and money market funds we have elected to classify as restricted assets that are included in other current assets and other assets. Also included is cash denominated in a foreign currency we have elected to classify as restricted that is included in current assets of discontinued operations and limited to remaining liabilities of discontinued operations. For these items, quoted current market prices are readily available. At September 30, 2011, Level 2 inputs include a bank certificate of deposit, which is 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, 2011: Total Measured at Fair Value $364,246 332,669 23,544 2,000 Assets: Cash and cash equivalents Investments Other current assets Other assets Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) $364,246 332,669 23,294 2,000 $ — — 250 — $250 $— — — — $— Total assets measured at fair value $722,459 $722,209 The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2011 and September 30, 2010. September 30, Carrying value of long-term fixed-rate debt Fair value of long-term fixed-rate debt 2011 2010 (in thousands) $350.0 $376.9 $350.0 $382.9 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. The debt was valued using a Level 2 input. 92 NOTE 9 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of other comprehensive income (loss) for the years ended September 30, 2011, 2010 and 2009 were as follows: Years Ended September 30, 2011 2010 (in thousands) 2009 Unrealized appreciation (depreciation) on securities, net of tax of $11,047, $(13,730) and $54,254 $18,414 $(22,885) $ 88,519 Amortization of net periodic benefit costs – net of actuarial gain, net of tax of $(2,167), $(3,276) and $(8,872) (3,613) $14,801 (5,459) $(28,344) (14,475) $ 74,044 The components of accumulated other comprehensive income (loss) at September 30, 2011 and 2010, net of applicable tax effects, were as follows: September 30, Unrealized appreciation on securities Unrecognized actuarial loss and prior service cost 2011 2010 (in thousands) $126,126 (27,218) $ 98,908 $107,712 (23,605) $ 84,107 93 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. 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, 2011 and a statement of the funded status as of September 30, 2011 and 2010: Accumulated Benefit Obligation Changes in projected benefit obligations 2011 2010 (in thousands) $104,911 $102,097 Projected benefit obligation at beginning of year $102,097 $ 89,996 Interest cost Actuarial gain Benefits paid 4,519 2,411 (4,116) 4,825 11,482 (4,206) Projected benefit obligation at end of year $104,911 $102,097 Change in plan assets Fair value of plan assets at beginning of year $ 61,388 $ 57,181 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 The amounts recognized in the Consolidated Balance Sheets are as follows (in thousands): Accrued liabilities Noncurrent liabilities – other Net amount recognized The amounts recognized in Accumulated Other Comprehensive Income at September 30, 2011 and 2010, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial gain (loss) Prior service cost Total (1,323) 11,335 (4,116) $ 67,284 $ (37,627) $ (68) (37,559) $ (37,627) $ (43,781) (2) $ (43,783) 5,005 3,408 (4,206) $ 61,388 $ (40,709) $ (181) (40,528) $ (40,709) $ (38,001) (2) $ (38,003) 94 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 $3.5 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 2011 4.48% 4.33% 8.00% 2010 5.42% 4.48% 8.00% 2009 7.25% 5.42% 8.00% We contributed $11.3 million to the Pension Plan in fiscal 2011 to fund distributions in lieu of liquidating pension assets. We estimate contributing at least $0.8 million in fiscal 2012 to meet the minimum contribution required by law and expect to make additional contributions in fiscal 2012 if needed to fund unexpected distributions. Components of the net periodic pension expense (benefit) were as follows: Years Ended September 30, Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Settlement/curtailment Net pension expense (benefit) 2011 $ 4,519 (5,050) — 2,976 28 $ 2,473 2010 (in thousands) $ 4,825 (4,552) — 2,295 — $ 2,568 2009 $ 4,988 (4,643) (1) 3 — $ 347 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). 2012 $6,171 2013 $5,626 2014 $5,278 2015 $5,965 2016 $6,678 2017-2021 $35,649 Total $65,367 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 single investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Plan assets are invested in portfolios of diversified public-market equity securities and fixed income securities. The Plan holds no securities of the Company. 95 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 Plan’s investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes. The target allocation for 2012 and the asset allocation for the Pension Plan at the end of fiscal 2011 and 2010, by asset category, follows: Asset Category U.S. equities International equities Fixed income Real estate and other Total Target Allocation Percentage of Plan Assets At September 30, 2012 56% 14 25 5 100% 2011 56% 13 30 1 100% 2010 53% 15 31 1 100% PLAN ASSETS The fair value of Plan assets at September 30, 2011 and 2010, summarized by level within the fair value hierarchy described in Note 8, are as follows: Fair Value as of September 30, 2011 Level 3 Level 1 Level 2 Total Short-term investments Mutual funds: Domestic stock funds Bond funds International stock funds Total mutual funds Domestic common stock Common collective trust Foreign equity stock Oil and gas properties Total $ 156 $ (in thousands) 156 $ — $ — 28,288 20,127 8,848 28,288 20,127 8,848 57,263 57,263 8,252 8,252 535 803 275 — 803 — — — — — — 535 — — $67,284 $66,474 $535 — — — — — — — 275 $275 96 Fair Value as of September 30, 2010 Level 3 Level 2 Level 1 Total Short-term investments Mutual funds: Domestic stock funds Bond funds International stock funds Total Mutual funds Domestic common stock Common collective trust Foreign equity stock Oil and gas properties Total (in thousands) $ 63 $ 63 $ — $ — 17,858 18,872 8,956 45,686 13,710 785 869 275 17,858 18,872 8,956 45,686 13,710 — 869 — — — — — — 785 — — $61,388 $60,328 $785 — — — — — — — 275 $275 The Plan’s financial assets utilizing Level 1 inputs include publicly traded mutual funds, common stock and foreign equity stocks. These assets are valued based on quoted prices in active markets for identical securities. The Plan’s financial assets utilizing Level 2 inputs include a common collective trust (Wells Fargo Short-term Investment Fund). The statements of net assets available for benefits present the fair value of the Wells Fargo Short-term Investment Fund. The Plan’s interest in the common collective trust is valued at net asset value per unit provided by the Plan’s trustee. The Plan’s financial instruments utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets. The following table sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the years ended September 30, 2011 and 2010: Years Ended September 30, Balance, beginning of year Unrealized losses relating to property still held at the reporting date Balance, end of year Oil and Gas Properties 2011 2010 (in thousands) $275 — $275 $435 (160) $275 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 $21.0 million, $14.2 million and $14.3 million in fiscal 2011, 2010 and 2009, respectively. 97 NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for 2011, 2010 and 2009: 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, 2011 2010 2009 (in thousands) $ 830 106 (160) $ 776 $659 206 (35) $830 $1,331 (645) (27) $ 659 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 Total accounts receivable, net of reserve Prepaid expenses and other: Restricted cash Prepaid insurance Deferred mobilization Prepaid value added tax Other 2011 2010 (in thousands) $460,540 — $460,540 $409,920 47,739 $457,659 $ 16,015 $ 12,848 10,117 8,512 3,884 11,208 9,196 14,430 15,481 12,216 Total prepaid expenses and other $ 49,736 $ 64,171 Accrued liabilities: Accrued operating costs Payroll and employee benefits Taxes payable, other than income tax Accrued income taxes Deferred mobilization Self-insurance liabilities Deferred income Other Total accrued liabilities Noncurrent liabilities – Other: Pension and other non-qualified retirement plans Self-insurance liabilities Deferred mobilization Deferred income Uncertain tax positions including interest and penalties Other $ 50,415 43,077 37,789 17,075 11,281 5,452 4,073 23,736 $ 23,436 33,392 44,934 — 13,522 4,135 6,438 18,255 $192,898 $144,112 $ 50,225 13,780 12,033 10,569 9,829 7,849 $ 51,690 5,328 7,816 14,983 6,755 5,034 Total noncurrent liabilities – other $104,285 $ 91,606 98 NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, Cash payments: Interest paid, net of amounts capitalized Income taxes paid 2011 $16,107 $19,621 2010 (in thousands) $ 16,721 $104,028 2009 $12,196 $31,009 Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2011, 2010 and 2009 do 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 2011 $730,347 25,508 2010 (in thousands) $345,264 9,816 2009 $819,798 66,857 year (61,591) (25,508) (9,816) Capital expenditures per Consolidated Statements of Cash Flows $694,264 $329,572 $876,839 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. 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. Except as disclosed in Note 2, Discontinued Operations, 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 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 a customer’s future spending levels. This volatility, along with the difficulty in predicting future prices, can lead 99 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. Any deterioration in the credit and capital markets may 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 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 liability and automobile liability. Insurance coverage has been purchased for individual claims that exceed $1 million or $2 million, depending on whether a claim occurs outside or inside of the United States. 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 adjusters’ estimates, 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, which provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles and a stop-loss on our self-insured health plan. 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. INTERNATIONAL DRILLING OPERATIONS International drilling operations may significantly contribute 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, modified exchange controls, changes in international regulatory requirements and international employment issues, risk of expropriation of real and personal property 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 potentially causing an adverse material 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. 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 COMMITMENTS AND CONTINGENCIES COMMITMENTS During fiscal 2011, we announced agreements to build and operate 58 new FlexRigs. Subsequent to September 30, 2011, we announced that agreements had been reached to build and operate 17 additional FlexRigs. As of November 17, 2011, 47 new FlexRigs with customer commitments remained under construction. 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, 2011, we had purchase orders outstanding of approximately $361.3 million for the purchase of drilling equipment. LEASES At September 30, 2011, we were leasing approximately 135,000 square feet of office space near downtown Tulsa, Oklahoma. We also lease 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 a year at September 30, 2011 are as follows: Fiscal Year 2012 2013 2014 2015 2016 Thereafter Total Amount (in thousands) $ 5,979 4,557 2,524 2,343 1,961 6,489 $23,853 Total rent expense was $5.8 million, $5.4 million and $5.2 million for fiscal 2011, 2010 and 2009, respectively. 101 CONTINGENCIES 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. During the ordinary course of our business, contingencies arise resulting from an existing condition, situation, or set of circumstances involving an uncertainty as to the realization of a possible gain contingency. We account for gain contingencies in accordance with the provisions of ASC 450, Contingencies, and, therefore, we do not record gain contingencies and recognize income until realized. As discussed in Note 2, Discontinued Operations, property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in two arbitrations against third parties not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $75 million relating to the seizure of our property in Venezuela. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements. NOTE 15 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 Colombia, Ecuador, Argentina, Tunisia, Bahrain 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 a single 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. 102 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 • direct operating costs • depreciation and • allocated general and administrative costs but excludes corporate costs for other depreciation, income from asset sales and other corporate income and expense. General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods which 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 certain 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. 103 Summarized financial information of our reportable segments for continuing operations for each of the years ended September 30, 2011, 2010 and 2009 is shown in the following table: (in thousands) 2011 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 $2,100,508 $ — $2,100,508 $691,615 $264,127 $3,719,387 $694,249 201,417 226,849 2,528,774 15,120 2,543,894 — — — 829 829 201,417 45,291 14,684 151,656 7,092 226,849 19,711 28,018 333,142 20,638 2,528,774 756,617 306,829 4,204,185 721,979 15,949 (7,682) 8,639 792,177 8,368 2,544,723 748,935 315,468 4,996,362 730,347 Eliminations — (829) (829) — — — — Total $2,543,894 $ — $2,543,894 $748,935 $315,468 $4,996,362 $730,347 2010 Contract Drilling U.S. Land Offshore International Land Other $1,412,495 $ — $1,412,495 $404,278 $211,652 $3,257,382 $305,206 202,734 247,179 1,862,408 12,754 1,875,162 — — — 814 814 202,734 53,069 12,519 132,342 9,982 247,179 48,271 29,938 411,339 23,865 1,862,408 505,618 254,109 3,801,063 339,053 13,568 (6,765) 8,549 454,037 6,211 1,875,976 498,853 262,658 4,255,100 345,264 Eliminations — (814) (814) — — — — Total $1,875,162 $ — $1,875,162 $498,853 $262,658 $4,255,100 $345,264 2009 Contract Drilling U.S. Land Offshore International Land Other $1,441,164 $ — $1,441,164 $573,708 $187,259 $2,955,574 $703,073 204,702 187,099 1,832,965 10,775 1,843,740 — — — 836 836 204,702 55,293 11,872 129,465 17,584 187,099 18,955 19,278 391,099 94,627 1,832,965 647,956 218,409 3,476,138 815,284 11,611 (7,032) 9,126 532,346 4,514 1,844,576 640,924 227,535 4,008,484 819,798 Eliminations — (836) (836) — — — — Total $1,843,740 $ — $1,843,740 $640,924 $227,535 $4,008,484 $819,798 104 The following table reconciles segment operating income to income from continuing operations before income taxes and equity in income of affiliate as reported on the Consolidated Statements of Income: Years Ended September 30, Segment operating income Income from asset sales Gain from involuntary conversion of long-lived assets 2011 2010 2009 $ 748,935 13,903 — (in thousands) $ 498,853 $ 640,924 4,992 — 5,402 541 Corporate general and administrative costs and corporate depreciation (60,327) (52,049) (37,992) Operating income Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Total unallocated amounts 702,511 451,796 608,875 1,951 1,811 2,755 (17,355) (17,158) (13,590) 913 (953) — 1,787 — 245 (15,444) (13,560) (10,590) Income from continuing operations before income taxes and equity in income of affiliate $ 687,067 $ 438,236 $ 598,285 The following table presents revenues from external customers and long-lived assets by country based on the location of service provided: Years Ended September 30, Revenues United States Colombia Argentina Ecuador Other Foreign Total Long-Lived Assets United States Argentina Colombia Ecuador Other Foreign Total 2011 2010 2009 (in thousands) $2,276,118 $1,572,139 $1,613,940 74,504 44,205 42,598 57,533 55,855 52,115 106,469 137,520 77,322 42,087 52,250 58,141 $2,543,894 $1,875,162 $1,843,740 $3,423,185 $2,973,712 $2,879,222 78,221 67,369 28,439 79,856 91,322 59,798 27,772 99,896 62,942 26,022 122,416 126,191 $3,677,070 $3,275,020 $3,194,273 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling business accounted for approximately 12.5 percent of total operating revenues during the years ended September 30, 2011 and 2010 and 10.1 percent of the total operating revenues during the year ended September 30, 2009. Revenues from 105 another company doing business with the contract drilling business accounted for approximately 11.5 percent, 10.6 percent and 12.4 percent of total operating revenues during the years ended September 30, 2011, 2010 and 2009, respectively. Collectively, the receivables from these customers were approximately $95.5 million and $85.1 million at September 30, 2011 and 2010, respectively. NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) 2011 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues Operating income Income from continuing operations Net income Basic earnings per common share: Income from continuing operations Net income Diluted earnings per common share: Income from continuing operations Net income 2010 Operating revenues Operating income Income from continuing operations Net income (loss) Basic earnings per common share: Income from continuing operations Net income (loss) Diluted earnings per common share: Income from continuing operations Net income (loss) $594,642 170,726 104,365 104,150 $604,406 164,265 98,961 98,790 $644,095 $700,751 174,418 109,828 109,826 193,102 121,514 121,420 0.98 0.98 0.96 0.96 0.92 0.92 0.91 0.91 1.02 1.02 1.01 1.01 1.13 1.13 1.11 1.11 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $396,242 105,384 63,802 63,235 $436,579 101,706 74,105 46,747 $483,384 111,474 64,883 (36,715) $558,957 133,232 83,291 83,045 0.61 0.60 0.60 0.59 0.70 0.44 0.68 0.43 0.61 (0.35) 0.61 (0.34) 0.78 0.78 0.77 0.77 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 2011, net income includes an after-tax gain from the sale of assets of $1.7 million, $0.02 per share on a diluted basis. In the second quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.6 million, $0.02 per share on a diluted basis. 106 In the third quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.2 million, $0.02 per share on a diluted basis, and an after-tax gain from the sale of investment securities of $0.6 million, $0.01 per share on a diluted basis. In the fourth quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.4 million, $0.02 per share on a diluted basis. In the first quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $0.7 million, $0.01 per share on a diluted basis. In the second quarter of fiscal 2010, 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 third quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $1.5 million, $0.01 per share on a diluted basis. In the fourth quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $0.5 million with no effect on diluted earnings per share. NOTE 17 SUBSEQUENT EVENTS We have evaluated events and transactions occurring after the balance sheet date through the date these consolidated financial statements were issued, and have determined we have no recognized subsequent events. Subsequent to September 30, 2011, we sold two conventional rigs from our U.S. Land segment. 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 $250 $200 $150 $100 $50 $0 2006 2007 2008 2009 2010 2011 Helmerich & Payne, Inc. S&P 500 Index S&P 500 Oil & Gas Drilling Index 29NOV201114412659 107 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 * Member, Audit Committee ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee 108 W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer John W. Lindsay Executive Vice President and Chief Operating Officer Stockholders’ Meeting The annual meeting of stockholders will be held on March 7, 2012. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 24, 2012. 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, General Counsel & Chief Administrative Officer Stock Transfer Agent and Registrar As of November 17, 2011, there were 578 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. Juan Pablo Tardio Vice President and Chief Financial Officer 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. 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 18NOV201111532996 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 ANNUAL REPORT FOR 2011 

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