Helmerich & Payne
Annual Report 2008

Plain-text annual report

HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2008 26NOV200818032160 Helmerich & Payne, Inc. is the holding Company for H e l m e r i c h & Pa y n e , I n c . Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore operations in the United States, South America, and Africa. Holdings also include commercial real estate properties in the Tulsa, Oklahoma area, and an energy-weighted portfolio of securities valued at approximately $384 million as of September 30, 2008. F I N A N C I A L H I G H L I G H T S 26NOV200818032160 Years Ended September 30, 2008 2007 2006 Operating Revenues Net Income Diluted Earnings per Share Dividends Paid per Share Capital Expenditures Total Assets (in thousands, except per share amounts) $2,036,543 461,738 4.34 0.1850 705,635 3,588,045 $1,629,658 449,261 4.27 .1800 894,214 2,885,369 $1,224,813 293,858 2.77 .1725 528,905 2,134,712 To the Co-owners of Helmerich & Payne, Inc.: The Company enjoyed another record year in 2008, as we surpassed our high-water mark for revenue and net income for the third consecutive year. The year saw energy prices skyrocket and then spiral downward in the face of the recent economic meltdown. Today, we find the business in a sudden and dramatic reversal of fortune as future exploration and production spending plans are in the process of being aggressively scaled back. At the time of this writing, natural gas prices are less than half, and oil prices are slightly more than one-third of what they were at their highs during the summer. As late as October, we would have predicted a softer 2009 that would likely unfold in a similar fashion to what we saw in 2007; then, natural gas price concerns, combined with worries of potential overbuilding, softened the market enough to see 400 U.S. rigs sidelined. Many observers expect a similar number of rigs to be idled in 2009. A more sobering comparison may be in order, bringing to mind the correction the industry experienced in 2002, where nearly 50% of the industry’s U.S. rigs were idled. This story continues to unfold as we speak, and one obvious factor influencing the depth and longevity of the correction is how cold the current winter will be. While that speaks to the demand side, it is clear that E&P companies are not waiting for that outcome before they act. They are sidelining rigs today, reflecting concerns of the sizeable production growth experienced year over year. This is a move which will at some point impact the supply side of the equation and stands in contrast to the general approach taken in 2007 of ‘‘drilling through’’ the soft spots. In the event that a more severe response plays out, the result should have a purging effect that acts in a self-correcting way to shorten the down cycle. While no one can predict how things will develop for the land drillers, we believe the Company is uniquely positioned to weather the slowdown. Let me quickly hit some highlights to make this point. (cid:129) We have the newest and most capable fleet. Other downturns have seen us sustain higher utilizations and daily margins than our peers. When the smoke clears and operators rationalize their rig rosters, performance and efficiency will still win the day in their choice of rigs to engage. (cid:129) We have never had stronger contractual coverage: 58% of our 2009 fiscal year potential revenue days are under term contracts, and 43% of our 2010 revenue days are under term contracts. (cid:129) Our customer roster distinguishes itself with about 80% majors or super independents. They not only have the best ‘‘staying power,’’ but will likely look for opportunities to upgrade their rig rosters. (cid:129) With November’s announcement of 13 additional new build orders with long-term commitments, our manufacturing visibility extends into the early fall of 2009. That compares with November 2007, when our order book only took us into the following February. (cid:129) The Company’s international and offshore operations are operating at high utilization levels. Seven new FlexRigs(cid:2) will become fully operational during 2009 in Colombia and Argentina, and we have high expectations for the potential of the FlexRig in international markets. (cid:129) The strength of our balance sheet continues to allow us to fund the largest single year of new build orders, totaling 63, in the Company’s history. These new rigs, all at attractive dayrates, will act as an important counterbalance to softening spot rates going forward. It is important to remember that the seeds of recovery lie in the fact of the rapid depletion profile or a ‘‘blow down’’ of over 30% for domestic natural gas production. When the cycle does improve, the most promising shale and other unconventional plays still require extensive drilling with increasing technical challenges and today, over 70% of our FlexRigs are engaged with this type of play. We will continue to focus on strong field performance, where our people win the confidence of the customer every day. It is because of the efforts of our people that we have achieved our brand leadership, and it is to their credit that the Company reported record earnings in 2008. Our 88 years in this business help prepare us for the challenges and the opportunities that lie ahead. Sincerely, 11DEC200619131880 Hans Helmerich President November 21, 2008 Financial & Operating Review Years Ended September 30, 2008 2007 2006 SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*† Operating Revenues Operating Costs, excluding depreciation Depreciation** General and Administrative Expense Operating Income (loss) Interest and Dividend Income Gain on Sale of Investment Securities Interest Expense Net Income from Continuing Operations Net Income Diluted Earnings Per Common Share: Net Income from Continuing Operations Net Income *$000’s omitted, except per share data †All data excludes discontinued operations except net income. **2004 includes an asset impairment of $51,516 and depreciation of $94,425 SUMMARY FINANCIAL DATA* Cash** Working Capital** Investments Property, Plant, and Equipment, Net** Total Assets Long-term Debt Shareholders’ Equity Capital Expenditures *$000’s omitted **Excludes discontinued operations. RIG FLEET SUMMARY Drilling Rigs – U. S. Land – FlexRigs U. S. Land – Highly Mobile U. S. Land – Conventional Offshore Platform International Land Total Rig Fleet Rig Utilization Percentage – U. S. Land – FlexRigs U. S. Land – Highly Mobile U. S. Land – Conventional U. S. Land – All Rigs Offshore Platform International Land $2,036,543 1,086,666 210,766 57,059 692,816 5,038 21,994 18,689 461,738 461,738 $1,629,658 862,254 146,042 47,401 632,319 4,234 65,458 10,126 449,261 449,261 $1,224,813 661,563 101,583 51,873 417,286 9,834 19,866 6,644 293,858 293,858 4.34 4.34 4.27 4.27 2.77 2.77 $ 121,513 381,690 199,266 2,682,251 3,588,045 475,000 2,265,474 705,635 $ 89,215 272,352 223,360 2,152,616 2,885,369 445,000 1,815,516 894,214 $ 33,853 164,143 218,309 1,483,134 2,134,712 175,000 1,381,892 528,905 146 12 27 9 30 224 100 83 80 96 75 82 118 12 27 9 27 193 100 93 87 97 65 90 73 12 28 9 27 149 100 100 95 99 69 90 2005 2004 2003 2002 2001 2000 1999 1998 $ 800,726 484,231 96,274 41,015 192,756 5,809 26,969 12,642 127,606 127,606 $ 589,056 417,716 145,941 37,661 (6,885) 1,965 25,418 12,695 4,359 4,359 $ 504,223 346,259 82,513 41,003 38,137 2,467 5,529 12,289 17,873 17,873 $ 523,418 362,133 61,447 36,563 64,667 3,624 24,820 980 53,706 63,517 $ 528,187 331,063 49,532 28,180 123,613 9,128 1,189 1,701 80,467 144,254 $ 383,898 249,318 77,317 23,306 34,826 18,215 13,295 2,730 36,470 82,300 $ 430,475 288,969 70,092 24,629 49,024 4,830 2,547 5,389 32,115 42,788 $ 476,750 321,798 58,187 21,299 78,077 5,942 38,421 336 80,790 101,154 1.23 1.23 .04 .04 .18 .18 .53 .63 .79 1.42 .36 .82 .32 .43 .80 1.00 $ 288,752 410,316 178,452 981,965 1,663,350 200,000 1,079,238 86,805 $ 65,296 185,427 161,532 998,674 1,406,844 200,000 914,110 90,212 $ 38,189 110,848 158,770 1,058,205 1,417,770 200,000 917,251 242,912 $ 46,883 105,852 150,175 897,445 1,227,313 100,000 895,170 312,064 $ 128,826 223,980 203,271 650,051 1,300,121 50,000 1,026,477 184,668 $ 107,632 179,884 307,425 526,723 1,200,854 50,000 955,703 65,820 $ 21,758 82,893 240,891 553,769 1,073,465 50,000 848,109 78,357 $ 24,476 49,179 200,400 548,555 1,053,200 50,000 793,148 217,597 50 12 29 11 26 128 100 99 82 94 53 77 48 11 28 11 32 130 99 91 67 87 48 54 43 11 29 12 32 127 97 89 58 81 51 39 26 11 29 12 33 111 96 97 70 84 83 51 13 11 25 10 37 96 100 89 99 97 98 56 6 10 22 10 40 88 99 95 77 85 94 47 6 11 23 10 39 89 79 90 61 69 95 53 6 7 23 10 44 90 100 100 92 94 99 88 Helmerich & Payne, Inc. F O R M 1 0 - K , 2 0 0 8 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, 2008 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 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) Non-accelerated filer (cid:3) (Do not check if a smaller reporting company) Smaller reporting company (cid:3) 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, 2008 the aggregate market value of the voting stock held by non-affiliates was $4,722,260,676 Number of shares of common stock outstanding at November 20, 2008: 105,225,049 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, 2008 (2) Proxy Statement for Annual Meeting of Stockholders to be held March 4, 2009 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 5, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 33 THROUGH 69 OF THE COMPANY’S ANNUAL REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. i HELMERICH & PAYNE, INC. FORM 10-K YEAR ENDED SEPTEMBER 30, 2008 TABLE OF CONTENTS PART I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Item 3. Item 4. Item 5. Item 6. Item 7. Properties Legal Proceedings Submission of Matters to a Vote of Security Holders Executive Officers of the Company PART II Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion & Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation PART III Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services Item 15. Exhibits and Financial Statement Schedules SIGNATURES PART IV Page 1 5 12 12 18 18 18 19 19 20 20 20 20 20 23 24 24 24 24 24 25 29 ii (This page intentionally left blank.) HELMERICH & PAYNE, INC. AND SUBSIDIARIES Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 2008 Item 1. BUSINESS PART I Helmerich & Payne, Inc. (the ‘‘Company’’), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. The Company is primarily engaged in contract drilling of oil and gas wells for others and this business accounts for almost all of the Company’s operating revenues. The Company’s contract drilling business is composed of three reportable business segments: U.S. land drilling, offshore drilling and international land drilling. The Company’s U.S. land drilling is conducted primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Alabama, Utah, Arkansas, New Mexico, and North Dakota. Offshore drilling operations are conducted in the Gulf of Mexico, and offshore of California, Trinidad and Equatorial Guinea. The Company’s international land segment operated in five international locations during fiscal 2008: Venezuela, Ecuador, Colombia, Argentina and Tunisia. The Company is also engaged in the ownership, development and operation of commercial real estate and, as a result of the recent acquisition discussed below, the research and development of rotary steerable technology. Both businesses operate independently of the other through wholly-owned subsidiaries. This operating decentralization though is balanced by a centralized finance division, which handles all accounting, information technology, budgeting, insurance, cash management and related activities. The Company’s real estate investments are located exclusively within Tulsa, Oklahoma, which 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. In May 2008, the Company acquired TerraVici Drilling Solutions, Inc. (‘‘TerraVici’’) for $12.2 million. The terms of the transaction provide for future contingency payments up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met. TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. The Company acquired TerraVici to complement technology currently used with the FlexRig. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with the Company’s existing capabilities, the Company expects to improve drilling productivity and reduce total well cost to the customer. CONTRACT DRILLING General The Company believes that it is one of the major land and offshore drilling contractors in the western hemisphere. Operating principally in North and South America, the Company specializes in shallow to deep drilling in oil and gas producing basins of the United States and in drilling for oil and gas in international locations. In the United States, the Company draws its customers primarily from the major oil companies and the larger independent oil companies. In South America, the Company’s current customers include the Venezuelan state petroleum company and major international oil companies. In fiscal 2008, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers. Devon Energy Production Co. LP, BP plc and Petroleos de Venezuela S.A. (respectively, ‘‘Devon’’, ‘‘BP’’ and ‘‘PDVSA’’), including their affiliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for Devon in U.S. land operations, BP on a world-wide basis and PDVSA in Venezuela. Revenues from drilling services performed for Devon, BP and PDVSA in fiscal 2008 accounted for approximately 10 percent, 8 percent and 8 percent, respectively, of the Company’s consolidated operating revenues for the same period. Rigs, Equipment and Facilities The Company provides drilling rigs, equipment, personnel and camps on a contract basis. These services are provided so that the Company’s customers may explore for and develop oil and gas from onshore areas and from fixed platforms, tension-leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drillstring and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A land drilling rig may be moved from location to location without modification to the rig. A platform rig is specifically designed to perform drilling operations upon a particular platform. While a platform rig may be moved from its original platform, significant expense is incurred to modify a platform rig for operation on each subsequent platform. In addition to traditional platform rigs, the Company operates self-moving platform drilling rigs and drilling rigs to be used on tension-leg platforms and spars. The self-moving rig is designed to be moved without the use of expensive derrick barges. The tension-leg platforms and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms. In 1998, the Company put to work a new generation of six highly mobile/depth flexible land drilling rigs (individually the ‘‘FlexRig(cid:2)’’). The FlexRig has been able to significantly reduce average rig move and drilling times compared to similar depth-rated traditional land rigs. In addition, the FlexRig allows a greater depth flexibility of between 8,000 to 18,000 feet and provides greater operating efficiency. The original six rigs were designated as FlexRig1 rigs. Subsequently, the Company built and completed 12 new FlexRig2 rigs. In 2001, the Company announced that it would build an additional 25 new FlexRigs. These new rigs, known as ‘‘FlexRig3 rigs’’, were the next generation of FlexRigs which incorporated new drilling technology and new environmental and safety design. This new design included integrated top drive, AC electric drive, hydraulic BOP handling system, hydraulic tubular make-up and break-out system, split crown and traveling blocks and an enlarged drill floor that enables simultaneous crew activities. All 25 of these FlexRig3s were completed by June of 2003. Subsequently, the Company constructed seven more FlexRig3s at an approximate cost of $11.2 million each. Construction of these rigs was completed by March of 2004. Since fiscal 2005, the Company has entered into separate drilling contracts with 25 exploration and production companies to build and operate a total of 127 new FlexRigs. Of the 127 FlexRigs, 49 are FlexRig3s and 78 are FlexRig4s (described below). Each of the drilling contracts provides for a minimum fixed contract term of at least three years, with drilling services to be performed on a daywork contract basis. At September 30, 2008, the Company had completed 102 of the 127 FlexRigs with the remaining 25 expected to be completed by the end of calendar 2009. The total construction cost for the 127-rig project is expected to approximate $2.0 billion, or approximately $15 million per FlexRig. While the new FlexRig3s are similar to the Company’s existing FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow depth wells of between 4,000 and 14,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate new environmental and safety design. This new design includes a pipe handling system which allows the rig to potentially be operated by a reduced crew and eliminates the need for a casing stabber in the mast. While the trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which results in reduced environmental impact. The effective use of technology is important to the maintenance of the Company’s competitive position within the drilling industry. As a result of the importance of technology to the Company’s business, we expect to continue to develop technology internally. The Company assembles new FlexRigs at its gulf coast facility near Houston, Texas, and also at the Company’s 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma. The Company’s Houston rig assembly facility and the facilities of its primary rig fabricator sustained minor damage and loss of power due to Hurricane Ike. However, there has been no material adverse effect upon the Company’s business, rig deliveries, operations or financial condition due to Hurricane Ike. Drilling Contracts The Company’s drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and often cover multi-well and multi-year projects. Each drilling rig operates 2 under a separate drilling contract. During fiscal 2008, all drilling services were performed on a ‘‘daywork’’ contract basis, under which the Company charges a fixed rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. The Company has previously performed contracts on a combination ‘‘footage’’ and ‘‘daywork’’ basis, under which the Company charged a fixed rate per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the remainder of the hole. Contracts performed on a ‘‘footage’’ basis involve a greater element of risk to the contractor than do contracts performed on a ‘‘daywork’’ basis. Also, the Company has previously accepted ‘‘turnkey’’ contracts under which the Company charges a fixed sum to deliver a hole to a stated depth and agrees to furnish services such as testing, coring and casing the hole which are not normally done on a ‘‘footage’’ basis. ‘‘Turnkey’’ contracts entail varying degrees of risk greater than the usual ‘‘footage’’ contract. The Company has not accepted any ‘‘footage’’ or ‘‘turnkey’’ contracts for at least the last ten years. The Company believes that under current market conditions, ‘‘footage’’ and ‘‘turnkey’’ contract rates do not adequately compensate contractors for the added risks. The duration of the Company’s drilling contracts are ‘‘well-to-well’’ or for a fixed term. ‘‘Well-to-well’’ contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts customarily provide for termination at the election of the customer, with an ‘‘early termination payment’’ to be paid to the Company if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, bankruptcy of the Company, sustained unacceptable performance by the Company or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. Excluding the fixed-term contracts covering the 102 new-build FlexRigs completed as of September 30, 2008, the Company had 16 rigs under fixed-term contracts as of the end of fiscal 2008. While the original duration for these current fixed-term contracts are for twelve-month to three-year periods, some fixed-term and well-to-well contracts are expected to be extended for longer periods than the original terms. However, the contracting parties have no legal obligation to extend the contracts. Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to the Company and the customer. In most instances contracts provide for additional payments for mobilization and demobilization. Backlog The Company’s contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of October 31, 2008 and 2007 was $3,374 million and $1,969 million, respectively. The increase in the Company’s backlog from 2007 to 2008 is primarily due to the execution of additional long-term contracts for the operation of new FlexRigs. Approximately 66.0 percent of the total October 2008 backlog is not reasonably expected to be filled in fiscal 2009. Term contracts customarily provide for termination at the election of the customer with an ‘‘early termination payment’’ to be paid to the Company if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, bankruptcy of the Company, sustained unacceptable performance by the Company or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. In addition, a portion of the backlog represents term contracts for new rigs that will be constructed in the future. The Company obtains certain key rig components from a single or limited number of vendors or fabricators. Certain of these vendors or fabricators are thinly capitalized independent companies located on the Texas gulf coast. Therefore, disruptions in rig component deliveries may occur. Accordingly, the actual amount of revenue earned may vary from the backlog reported. See ‘‘Item 1A. Risk Factors.’’ 3 The following table sets forth the total backlog by reportable segment as of October 31, 2008 and 2007, and the percentage of the October 31, 2008 backlog not reasonably expected to be filled in fiscal 2009: Reportable Segment U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Total Backlog Revenue 10/31/2008 10/31/2007 (in millions) $2,876 199 299 $3,374 $1,696 234 39 $1,969 Percentage Not Reasonably Expected to be Filled in Fiscal 2009 64.1% 75.1% 78.4% U.S. LAND DRILLING At the end of September 2008, 2007 and 2006, the Company had 185, 157 and 113 respectively, of its land rigs available for work in the United States. The total number of rigs at the end of fiscal 2008 increased by a net of 28 rigs from the end of fiscal 2007, resulting from new FlexRigs placed into service. The Company’s U.S. land operations contributed approximately 76 percent ($1,542.0 million) of the Company’s consolidated operating revenues during fiscal 2008, compared with approximately 72 percent ($1,174.9 million) of consolidated operating revenues during fiscal 2007 and approximately 68 percent ($829.1 million) of consolidated operating revenues during fiscal 2006. Rig utilization in fiscal 2008 was approximately 96 percent, down from approximately 97 percent in fiscal 2007 and 99 percent in 2006. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 98 percent during fiscal 2008 while the Company’s conventional rigs had an average utilization rate of approximately 80 percent. A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract. At the close of fiscal 2008, 182 land rigs were working out of 185 available rigs. OFFSHORE DRILLING The Company’s offshore operations contributed approximately 8 percent ($154.5 million in fiscal 2008 and $123.1 million in fiscal 2007) of the Company’s consolidated operating revenues during both fiscal years, compared to approximately 13 percent ($154.5 million) of the Company’s consolidated operating revenues during fiscal 2006. Rig utilization in fiscal 2008 was approximately 75 percent, up from approximately 65 percent in fiscal 2007 and 69 percent in 2006. At the end of fiscal 2008, the Company had eight of its nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. The management contract for one rig located offshore Equatorial Guinea terminated in early fiscal 2008 but the Company has continued under a standby contract. The Company is currently negotiating a new long-term contract in Equatorial Guinea, and the Company anticipates returning to a full dayrate in fiscal 2010. Revenues from drilling services performed for the Company’s largest offshore drilling customer totaled approximately 40 percent of offshore revenues during fiscal 2008. INTERNATIONAL LAND DRILLING General The Company’s international land operations contributed approximately 16 percent ($328.2 million) of the Company’s consolidated operating revenues during fiscal 2008, compared with approximately 20 percent ($320.3 million) of consolidated operating revenues during fiscal 2007 and 19 percent ($230.8 million) in fiscal 2006. Rig utilization in fiscal 2008 was 82 percent and 90 percent in fiscal 2007 and 2006. Venezuela Venezuelan operations continue to be a significant part of the Company’s operations. The Company worked exclusively for the Venezuelan state petroleum company, PDVSA and a PDVSA-owned affiliate, during fiscal 2008 and revenues from this work accounted for approximately 51 percent of international operating revenues. Revenues generated from Venezuelan drilling operations contributed approximately 4 8 percent ($167.2 million in fiscal 2008 and $127.3 million in fiscal 2007) of the Company’s consolidated operating revenues for both fiscal years compared to approximately 7 percent ($84.6 million) of consolidated operating revenues during fiscal 2006. The Company had 11 rigs working in Venezuela at the end of fiscal 2008. The Company’s rig utilization rate in Venezuela increased from approximately 92 percent during fiscal 2007 to approximately 97 percent in fiscal 2008. Rig utilization in 2006 was 83 percent. Ecuador At the end of fiscal 2008, the Company had four rigs in Ecuador. During fiscal 2008, the Company transferred two rigs from Ecuador to Colombia and sold two rigs that had been idle. The Company’s utilization rate was 59 percent during fiscal 2008, down from 89 percent in fiscal 2007 and 100 percent in fiscal 2006. Revenues generated by Ecuadorian drilling operations contributed approximately 3 percent ($55.1 million) of the Company’s consolidated operating revenues during fiscal 2008, as compared with approximately 6 percent ($93.9 million) of consolidated operating revenues during fiscal 2007 and approximately 7 percent ($88.7 million) of consolidated operating revenues during fiscal 2006. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 1 percent of consolidated operating revenues and approximately 6 percent of international operating revenues during fiscal 2008. The Ecuadorian drilling contracts are primarily with large international or national oil companies. Other Locations In addition to its operations in Venezuela and Ecuador, at the end of fiscal 2008, the Company had five rigs in Argentina, five rigs in Colombia and one rig in Tunisia. Additionally, four new FlexRigs were completed and ready for delivery at September 30, 2008. At the end of October 2008, all rigs in Argentina, Colombia and Tunisia were fully contracted. Two FlexRigs were mobilized to Colombia and commenced operations. Five FlexRigs, including the three rigs completed as of September 30, 2008, are scheduled to be mobilized to Argentina during fiscal 2009. FINANCIAL Information relating to revenues, total assets and operating income by reportable operating segments may be found on, and is incorporated by reference to, pages 77 through 81 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). EMPLOYEES The Company had 6,198 employees within the United States (14 of which were part-time employees) and 1,172 employees in international operations as of September 30, 2008. AVAILABLE INFORMATION Information relating to the Company’s internet address and the Company’s SEC filings may be found on, and is incorporated by reference to, page 83 of the Company’s Annual Report (Exhibit 13 to this Form 10-K). Item 1A. RISK FACTORS In addition to the risk factors discussed elsewhere in this Report, the Company cautions that the following ‘‘Risk Factors’’ could have a material adverse effect on the Company’s business, financial condition and results of operations. A deteriorating global economy may affect the Company’s business. As a result of recent volatility in oil and natural gas prices and substantial uncertainty in the capital markets due to the deteriorating global economic environment, the Company is unable to determine whether its customers will reduce spending on exploration and development drilling or whether customers 5 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 deteriorating global economic environment may impact industry fundamentals, and the potential resulting decrease in demand for drilling rigs could cause the drilling industry to cycle into a downturn. These conditions could have a material adverse effect on the Company’s business. The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, rig availability, efficiency, condition and type of equipment, reputation, operating safety, and customer relations. Competition is primarily on a regional basis and may vary significantly by region at any particular time. Land drilling rigs can be readily moved from one region to another in response to changes in levels of activity, and an oversupply of rigs in any region may result, leading to increased price competition. Although many contracts for drilling services are awarded based solely on price, the Company has been successful in establishing long-term relationships with certain customers which have allowed the Company to secure drilling work even though the Company may not have been the lowest bidder for such work. The Company has continued to attempt to differentiate its services based upon its FlexRigs and its engineering design expertise, operational efficiency, safety and environmental awareness. This strategy is less effective when lower demand for drilling services intensifies price competition and makes it more difficult or impossible to compete on any basis other than price. Also, future improvements in operational efficiency and safety by the Company’s competitors could negatively affect the Company’s ability to differentiate its services. The Company’s operations are subject to a number of operational risks, including weather. The drilling operations of the Company are subject to the many hazards inherent in the business, including inclement weather, blowouts and well fires. These hazards could cause personal injury, suspend drilling operations, seriously damage or destroy the equipment involved and cause substantial damage to producing formations and the surrounding areas. The Company’s offshore drilling operations are also subject to potentially greater environmental liability, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. Specifically, the Company operates several platform rigs in the Gulf of Mexico. The Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis. Damage caused by high winds and turbulent seas could potentially curtail operations on such platform rigs for significant periods of time until the damage can be repaired. Moreover, even if the Company’s platform rigs are not directly damaged by such storms, the Company may experience disruptions in operations due to damage to customer platforms and other related facilities in the area. The Company has a new-build rig assembly facility located near the Houston, Texas ship channel. Also, the Company’s principal fabricator and other vendors are located in the gulf coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage. 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 the Company if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, bankruptcy of the Company, sustained unacceptable performance by the Company or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the Company. Even if an early termination payment is owed to the Company, the recent deteriorating global economy may affect the customer’s ability to pay the early termination payment. The Company’s operations present risks of loss that, if not insured or indemnified against, could adversely affect our results of operations. The Company insures its rigs and equipment at estimated replacement cost at the inception of the policy. The Company self-insures 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 of its land 6 rigs and equipment. Damage from named wind storms is limited to $100 million in the aggregate and the per occurrence deductible increases to $3.5 million. Rig property insurance coverage expires in May 2009. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, the Company is generally indemnified under its drilling contracts from this risk. The Company has insurance coverage for comprehensive general liability, automobile liability, worker’s compensation and employer’s liability. Generally, casualty deductibles are $1 million or $2 million per occurrence, depending on whether a claim occurs inside or outside of the United States. The Company maintains certain other insurance coverages with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce the Company’s exposure to catastrophic events. The Company retains a significant portion of its expected losses under its worker’s compensation, general liability and automobile liability programs. The Company records estimates for incurred outstanding liabilities for unresolved worker’s compensation, general liability and for claims that are incurred but not reported. Estimates are based on adjuster estimates, historical experience or statistical methods that the Company believes are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. No assurance can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2009 or that insurance coverage will continue to be available at rates considered reasonable. No assurance can be given that the Company’s insurance and indemnification arrangements will adequately protect it against all liabilities that could result from the hazards of its drilling operations. Incurring a liability for which the Company is not fully insured or indemnified could materially affect the Company’s results of operations. 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 the Company’s business, financial condition and results of operations. The Company depends on a limited number of thinly capitalized vendors, the loss of any of which could disrupt the Company’s operations. Certain key rig components are either purchased from or fabricated by a single or limited number of vendors, and the Company has no long-term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply or increased demands in the industry. If the Company was unable to procure certain of such rig components, it would be required to reduce its rig construction or other operations, which could have a material adverse effect on the Company’s business, financial condition and results of operations. If the Company’s principal fabricator, located on the Texas gulf coast, was unable or unwilling to continue fabricating rig components, then the Company would have to transfer this work to other acceptable fabricators. This transfer could result in significant delay in the completion of new FlexRigs. Any significant interruption in the fabrication of rig components could have a material adverse impact on the Company’s business, financial condition and results of operations. Certain key rig components are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from the Company or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, 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 the Company’s business, financial condition and results of operations. 7 Oil and natural gas prices are volatile, and low prices could negatively affect our financial results in the future. The Company’s operations can be materially affected by low oil and gas prices. The Company believes that any significant reduction in oil and gas prices could depress the level of exploration and production activity and result in a corresponding decline in demand for the Company’s services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for the Company’s services could have a material adverse effect on the Company’s business, financial condition and results of operations. International uncertainties and local laws could adversely affect the Company’s business. International operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of terrorism, kidnapping of employees, expropriation of equipment as well as expropriation of a particular oil company operator’s property and drilling rights, taxation policies, foreign exchange restrictions, currency rate fluctuations and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. There can be no assurance that there will not be changes in local laws, regulations and administrative requirements or the interpretation thereof which could have a material adverse effect on the profitability of the Company’s operations or on the ability of the Company to continue operations in certain areas. Because of the impact of local laws, the Company’s future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which the Company holds only a minority interest or pursuant to arrangements under which the Company conducts operations under contract to local entities. While the Company believes that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on the Company’s operations or revenues, there can be no assurance that the Company will in all cases be able to structure or restructure its operations to conform to local law (or the administration thereof) on terms acceptable to the Company. Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in labor and/or materials and supplies necessary to operate some or all of its Venezuelan drilling rigs, which could have a material adverse effect on the Company’s business, financial condition and results of operations. During the mid-1970s, the Venezuelan government nationalized the exploration and production business. At the present time it appears the Venezuelan government will not nationalize the contract drilling business. Any such nationalization could result in the Company’s loss of all or a portion of its assets and business in Venezuela. Although the Company attempts to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2008, approximately 16 percent of the Company’s consolidated operating revenues were generated from the international contract drilling business. During fiscal 2008, approximately 95 percent of the international operating revenues were from operations in South America and approximately 71 percent of South American operating revenues were from Venezuela and Ecuador. The Company’s business and results of operations may be adversely affected by foreign currency devaluation. General Contracts for work in foreign countries generally provide for payment in United States dollars, except for amounts required to meet local expenses. However, government-owned petroleum companies are more frequently requesting that a greater proportion of these payments be made in local currencies. Based upon current information, the Company believes that exposure to potential losses from currency devaluation is immaterial in Colombia, Equatorial Guinea, Trinidad and Tunisia. In those countries, all receivables and payments are currently in U.S. dollars. Cash balances are kept at an insignificant level which assists in reducing exposure. 8 Argentina In 2002, Argentina suffered a 60 percent devaluation of the peso. The Company invoices in (USD) dollars and is paid in pesos equivalent to the dollar invoice. The Company remits the dollars to the parent by exchanging pesos through the Central Bank. The exchange rate between the U.S. dollar and the Argentine peso has stayed within a narrow range for the past seven years and in fiscal 2008, the Company experienced an immaterial currency loss. In order to establish a source of local currency to meet current obligations in Argentine pesos, the Company borrowed in the form of an unsecured short-term note from a local bank in Argentina at the market interest rate designated by the bank. The outstanding balance of approximately $1.7 million along with interest was paid in full subsequent to September 30, 2008. Venezuela On January 1, 2008, the Venezuelan government changed the official Venezuelan currency from the bolivar to the bolivar fuerte (2150 bolivars equals 2.15 bolivar fuerte). The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte receivable balances and bolivar fuerte cash balances. In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 percent in bolivar fuerte. The significance of this arrangement is that even though the dollar-based invoices may be paid in bolivar fuerte, the Company, historically, has usually been able to convert the bolivar fuerte into U.S. dollars in a timely manner and thus avoid, in large measure, devaluation losses pertaining to the dollar-based invoices paid in bolivar fuerte. However, this arrangement is effective only in the absence of exchange controls. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate and also prohibited the Company, as well as other companies, from converting bolivars into U.S. dollars through the Central Bank. As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivar balances into U.S. dollars. In compliance with such regulations, the Company, in October of 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which would convert 14 billion bolivars into U.S. dollars. In January 2004, the Venezuelan government approved the Company’s request to convert bolivar cash balances to U.S. dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S.-based parent. This was the first dividend remitted under the new regulation. On January 16, 2006, a dividend of $6.5 million U.S. dollars was remitted to the U.S.-based parent. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S.-based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by these amounts. On July 22, 2008, the Company made applications with the Venezuelan government requesting the approval to convert bolivar fuerte cash balances to U.S. dollars. When and if the Company receives approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S.-based parent, thus reducing the Company’s exposure to currency devaluation. While the Company has been successful in obtaining government approval for conversion of bolivar fuerte cash balances to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then bolivar fuerte cash balances would increase and expose the Company to increased risk of devaluation. As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte receivable and cash balances. As a result of a 12 percent devaluation of the bolivar during fiscal 2005, the Company experienced total devaluation losses of $0.6 million during that same period. Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Even though Venezuela continues to operate under the exchange controls in place and the Venezuelan bolivar fuerte exchange rate is fixed at 2.15 bolivar fuerte to one U.S. dollar, the exact amount and timing of devaluation is uncertain. At September 30, 2008, the Company had a $43.4 million cash balance 9 denominated in bolivar fuerte included in the balance sheet and exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2009 balance sheet components are similar to fiscal 2008, and if a 10 percent to 30 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $7 million to $18 million. The Company derives its revenue in Venezuela from PDVSA, the Venezuelan state-owned petroleum company. At the end of fiscal 2008, the Company had a net receivable from PDVSA of approximately $65.5 million, of which approximately $5.2 million was 90 days old or older. At November 1, 2008, such receivable balance had decreased to approximately $63.9 million, of which approximately $13.5 million was 90 days old or older. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. The Company’s Venezuelan subsidiary has received notification from PDVSA that reimbursement of U.S. dollar invoices previously paid in bolivar fuerte will be made only when supporting documentation has been approved. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $46.3 million. The Company is unable to determine the timing of when payment will be received. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than those of other foreign customers of the Company. However, the failure of PDVSA to make payments on outstanding receivables, or a continued increase in its delay in making payments could have a material adverse effect on the Company’s business, financial condition and results of operations. Government regulations and environmental laws could adversely affect the Company’s business. Many aspects of the Company’s operations are subject to government regulation, including those relating to drilling practices and methods and the level of taxation. In addition, the United States and various other countries have environmental regulations which affect drilling operations. Drilling contractors may be liable for damages resulting from pollution. Under United States regulations, drilling contractors must establish financial responsibility to cover potential liability for pollution of offshore waters. Generally, the Company is indemnified under drilling contracts from liability arising from pollution, except in certain cases of surface pollution. However, the enforceability of indemnification provisions in foreign countries may be questionable. The Company believes that it is in substantial compliance with all legislation and regulations affecting its operations in the drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance has not materially affected the capital expenditures, earnings, or competitive position of the Company, although these measures may add to the costs of drilling operations. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on operations cannot be predicted. Variable rate indebtedness subjects the Company to interest rate risk, which could cause our debt service obligations to increase significantly. At September 30, 2008, the Company had outstanding, $175 million intermediate-term unsecured debt with staged maturities from August 2009 to August 2014, with varying fixed interest rates for each maturity series. The average interest rate during the next four years on this debt is 6.5 percent, after which it increases to 6.6 percent. The fair value of this debt at September 30, 2008, was approximately $198 million. The Company has in place a $400 million senior unsecured credit facility which expires in December of 2011. The Company had $325 million borrowed and three letters of credit totaling $25.9 million outstanding against the facility at September 30, 2008. As of November 20, 2008, borrowings under the facility had declined to $290 million. The interest rate on the borrowings is based on a spread over LIBOR and the Company pays a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of the Company’s total debt to total capitalization. The Company also has the option to borrow at the prime rate for maturities of less than 30 days. 10 At November 26, 2008, the Company was in discussions with the syndicate leader of the current bank facility about securing another separate bank facility for $100 to $150 million. While there is no certainty that such a facility could be placed, the Company expects that one could be completed and funded by late December 2008 or January 2009. Should the Company be unable to secure additional financing, there is a risk that it would be forced to liquidate a portion of its investment portfolio at depressed market prices in order to fund its capital expenditures planned for 2009. The Company also has an agreement with a single bank for an unsecured line of credit for $5 million. The interest rate on borrowings is equal to the prime rate minus 1.75%. At September 30, 2008, the Company had no outstanding borrowings against the credit line. Interest rates could rise for various reasons in the future and increase the Company’s total interest expense, depending upon the amount borrowed against the credit lines. The Company’s securities portfolio may lose significant value due to a decline in equity prices and other market-related risks, thus impacting the Company’s debt ratio and financial strength. At September 30, 2008, the Company had a portfolio of securities with a total market value of $384 million. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the market value of the Company’s holdings. Except for the Company’s holdings in Atwood Oceanics, Inc. and investments in limited partnerships carried at cost, the portfolio is recorded at fair value on its balance sheet with changes in unrealized after-tax value reflected in the equity section of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial strength. At November 20, 2008, the market value of the portfolio had dropped to approximately $175 million. The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations. In fiscal 2008, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers and approximately 27 percent of its consolidated operating revenues from the Company’s three largest customers (including their affiliates). The Company believes that its relationship with all of these customers is good; however, the loss of one or more of its larger customers would have a material adverse effect on the Company’s business, financial condition and results of operations. Competition for experienced technical personnel may negatively impact our operations or financial results. The Company utilizes highly skilled personnel in operating and supporting its businesses. In times of high utilization, it can be difficult to find qualified individuals. Although to date the Company’s operations have not been materially affected by competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact the Company’s business, financial condition and results of operations. New technologies may cause the Company’s drilling methods and equipment to become less competitive, resulting in an adverse effect on the Company’s financial condition and results of operations. Although the Company takes measures to ensure that it uses advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make the Company’s equipment less competitive or require significant capital investments to keep its equipment competitive. 11 Item 1B. UNRESOLVED STAFF COMMENTS The Company has received no written comments regarding its periodic or current reports from the staff of the Securities and Exchange Commission that were issued 180 days or more preceding the end of its 2008 fiscal year and that remain unresolved. Item 2. PROPERTIES CONTRACT DRILLING The following table sets forth certain information concerning the Company’s U.S. drilling rigs as of September 30, 2008: Location FLEXRIGS TEXAS TEXAS TEXAS TEXAS TEXAS MISSISSIPPI NORTH DAKOTA NORTH DAKOTA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS COLORADO TEXAS OKLAHOMA TEXAS TEXAS TEXAS LOUISIANA TEXAS TEXAS TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS Rig Optimum Depth (Feet) Rig Type Drawworks: Horsepower 164 165 166 167 168 169 179 180 181 182 183 184 185 186 187 188 189 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 12 SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig1) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) SCR (FlexRig2) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Location TEXAS CALIFORNIA TEXAS TEXAS COLORADO CALIFORNIA NORTH DAKOTA TEXAS TEXAS TEXAS TEXAS TEXAS 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 COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO NEW MEXICO NEW MEXICO NEW MEXICO WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS COLORADO COLORADO Rig 235 236 237 238 239 240 241 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 Optimum Depth (Feet) Rig Type Drawworks: Horsepower AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) 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) 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 1,150 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,150 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 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 8,000 8,000 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 8,000 13 Location COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS UTAH TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS NEW MEXICO WYOMING WYOMING WYOMING WYOMING WYOMING TEXAS TEXAS TEXAS WYOMING COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO COLORADO TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS TEXAS NEW MEXICO OKLAHOMA TEXAS TEXAS OKLAHOMA TEXAS OKLAHOMA HIGHLY MOBILE RIGS ARKANSAS OKLAHOMA TEXAS WYOMING Rig 292 293 294 295 296 297 298 299 300 301 302 303 304 305 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 323 324 325 326 327 328 331 332 340 341 342 370 371 372 373 374 375 376 140 158 156 159 Optimum Depth (Feet) Rig Type Drawworks: Horsepower AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) AC (FlexRig3) Mechanical SCR Mechanical Mechanical 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 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 1,150 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 900 900 1,200 1,200 8,000 14,000 14,000 14,000 14,000 14,000 14,000 14,000 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 8,000 14,000 14,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 10,000 10,000 12,000 12,000 14 Location OKLAHOMA TEXAS OKLAHOMA TEXAS TEXAS TEXAS TEXAS COLORADO CONVENTIONAL RIGS OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS NORTH DAKOTA LOUISIANA OKLAHOMA LOUISIANA OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA OKLAHOMA TEXAS TEXAS LOUISIANA TEXAS LOUISIANA OKLAHOMA TEXAS LOUISIANA TEXAS TEXAS LOUISIANA LOUISIANA OFFSHORE PLATFORM RIGS TRINIDAD TEXAS GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO GULF OF MEXICO Rig 141 142 143 145 155 146 147 154 110 96 118 119 120 171 172 122 162 79 80 89 92 94 98 97 99 137 149 72 73 125 134 136 157 161 163 203 205 206 100 105 107 201 202 204 Optimum Depth (Feet) Rig Type Drawworks: Horsepower Mechanical Mechanical Mechanical Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Mechanical SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR Self-Erecting Self-Erecting Self-Erecting Conventional Conventional Conventional Tension-leg Tension-leg Tension-leg 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,500 700 1,000 1,200 1,200 1,200 1,000 1,000 1,700 1,500 2,000 1,500 1,500 1,500 1,500 1,500 2,000 2,000 2,000 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 14,000 14,000 14,000 14,000 14,000 16,000 16,000 16,000 12,000 16,000 16,000 16,000 16,000 16,000 16,000 16,000 18,000 20,000 20,000 20,000 20,000 20,000 20,000 26,000 26,000 26,000 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 15 The following table sets forth information with respect to the utilization of the Company’s U.S. land and offshore drilling rigs for the periods indicated: Years ended September 30, 2004 2005 2006 2007 2008 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) . . . . . . . . . . . . . . . . . . . . . 91 87 87% 94% 99% 97% 96% 113 157 185 11 11 9 48% 53% 69% 65% 75% 9 9 (1) A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract. 16 The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2008: Location Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina Colombia Colombia Colombia Colombia Colombia Colombia Ecuador Ecuador Ecuador Ecuador Tunisia Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Venezuela Rig 123 139 151 175 177 335 336 337 133 152 333 334 176 190 132 121 117 138 242 160 113 115 116 127 128 129 135 150 174 153 Optimum Depth (Feet) Rig Type Drawworks: Horsepower 26,000 30,000(cid:3) 30,000(cid:3) 30,000 30,000 8,000 8,000 8,000 30,000 30,000(cid:3) 8,000 8,000 18,000 26,000 18,000 20,000 26,000 26,000 18,000 26,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000(cid:3) SCR SCR SCR SCR SCR AC (FlexRig4) AC (FlexRig4) AC (FlexRig4) SCR SCR AC (FlexRig4) AC (FlexRig4) SCR SCR SCR SCR SCR SCR AC (FlexRig3) SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR SCR 2,100 3,000 3,000 3,000 3,000 1,150 1,150 1,150 3,000 3,000 1,150 1,150 1,500 2,000 1,500 1,700 2,500 2,500 1,500 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 The following table sets forth information with respect to the utilization of the Company’s international drilling rigs for the periods indicated: Years ended September 30, 2004 2005 2006 2007 2008 Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig utilization rate during period (1)(2) . . . . . . . . . . . . . . . . . . . . . 26 32 27 54% 77% 90% 90% 82% 27 30 (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 the stock portfolio held by the Company may be found on, and is incorporated by reference to, page 53 of the Company’s Annual Report under the caption, ‘‘Management’s Discussion & Analysis of Financial Condition and Results of Operations.’’ 17 Item 3. LEGAL PROCEEDINGS In connection with the Company’s Foreign Corrupt Practices Act training, questions were raised about the legality of certain past payments by one of the Company’s subsidiaries in connection with the passage of materials through customs in Latin America. In consultation with the Audit and Governance Committees of the Board of Directors, the Company engaged outside counsel and outside accountants to review these payments, other transactions of the subsidiary, and transactions at certain of the Company’s other operations in Latin America. Although the review is ongoing, outside counsel has substantially completed a review of such subsidiary as well as certain of the Company’s other operations in Latin America and, based on such review, the Company believes the amount of such questionable payments is not material, and the Company does not expect any material impact to the Company or its financial statements. The Company has contacted the Securities and Exchange Commission and the U.S. Department of Justice to inform them of this matter, and intend to cooperate fully with these governmental authorities. In addition, the Company is subject to various claims that arise in the ordinary course of its business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect the financial position, results of operations or liquidity of the Company. The Company is not a party to, and none of its property is subject to, any material pending legal proceedings. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE COMPANY The following table sets forth the names and ages of the Company’s executive officers, together with all positions and offices held with the Company by such executive officers. Officers are elected to serve until the meeting of the Board of Directors following the next Annual Meeting of Stockholders and until their successors have been duly elected and have qualified or until their earlier resignation or removal. W. H. Helmerich, III, 85 Chairman of the Board since 1960; Director since 1949 Hans Helmerich, 50 . . . President and Chief Executive Officer since 1989; Director since 1987 Douglas E. Fears, 59 . . . Executive Vice President and Chief Financial Officer since June 2008; Vice President and Chief Financial Officer since1988 Steven R. Mackey, 57 . . Executive Vice President, Secretary and General Counsel since June 2008; Secretary since 1990; Vice President and General Counsel since 1988 John W. Lindsay, 47 . . . Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. since 2006; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. since 1997 M. Alan Orr, 57 . . . . . . Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. since 2006; Vice President and Chief Engineer of Helmerich & Payne International Drilling Co. since 1992 Gordon K. Helm, 55 . . . Vice President and Controller. Vice President since 2008; Controller since 1993 18 PART II Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The principal market on which the Company’s common stock is traded is the New York Stock Exchange under the symbol ‘‘HP’’. The high and low sale prices per share for the common stock for each quarterly period during the past two fiscal years as reported in the NYSE-Composite Transaction quotations follow: Quarter 2007 2008 High Low High Low First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $27.65 31.00 36.57 36.76 $21.26 22.72 30.00 27.68 $40.60 47.89 77.24 75.38 $29.49 32.86 45.57 39.33 The Company paid quarterly cash dividends during the past two years as shown in the following table: Quarter Paid per Share Fiscal Total Payment Fiscal 2007 2008 2007 2008 First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $.045 .045 .045 .045 $.045 .045 .045 .050 $4,654,299 4,656,468 4,660,362 4,667,309 $4,678,511 4,685,576 4,706,051 5,272,654 Payment of future dividends will depend on earnings and other factors. As of November 21, 2008, there were 675 record holders of the Company’s common stock as listed by the transfer agent’s records. Item 6. SELECTED FINANCIAL DATA The following table summarizes selected financial information and should be read in conjunction with the Consolidated Financial Statements and the Notes thereto and the related Management’s Discussion & Analysis of Financial Condition and Results of Operations contained on pages 33 through 109 of the Company’s Annual Report. All per share amounts have been adjusted as a result of a two-for-one stock split effective June 26, 2006. 19 Five-year Summary of Selected Financial Data 2004 2005 2006 2007 2008 Operating revenues . . . . . . . . . . . . . . . . . Asset Impairment . . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . Income from continuing operations per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . Cash dividends declared per common $ 589,056 51,516 4,359 (in thousands except per share amounts) $1,224,813 — 293,858 $ 800,726 — 127,606 $1,629,658 — 449,261 $2,036,543 — 461,738 0.04 0.04 1,406,844 200,000 1.25 1.23 1,663,350 200,000 2.81 2.77 2,134,712 175,000 4.35 4.27 2,885,369 445,000 4.43 4.34 3,588,045 475,000 share . . . . . . . . . . . . . . . . . . . . . . . . . . 0.16125 0.165 0.1725 0.18 0.185 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 33 through 69 of the Company’s Annual Report under the caption ‘‘Management’s Discussion & Analysis of Financial Condition and Results of Operations.’’ Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found under the caption ‘‘Risk Factors’’ beginning on page 5 of this Report and on, and is incorporated by reference to, the following pages of the Company’s Annual Report under Management’s Discussion & Analysis of Financial Condition and Results of Operations and in Notes to Consolidated Financial Statements: Market Risk (cid:129) Foreign Currency Exchange Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Credit Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Commodity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Interest Rate Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (cid:129) Equity Price Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 64-66 66-67 67-68 68-69 69 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found on, and is incorporated by reference to, pages 71 through 105 of the Company’s Annual Report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. Item 9A. CONTROLS AND PROCEDURES a) Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2008. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that: (cid:129) the Company’s disclosure controls and procedures are effective at ensuring that information required to be disclosed by the Company in the reports it files or submits under the Securities 20 Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (cid:129) the Company’s disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to the Company’s management, and made known to the Company’s Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure. b) Management’s Report on Internal Control over Financial Reporting. Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the Board of Directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, conducted its evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal control over financial reporting, based on the Company’s evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2008. The Company’s independent registered public accounting firm that audited the Company’s financial statements, Ernst & Young LLP, has issued an attestation report on the Company’s internal control over financial reporting. This report appears below at the end of this Item 9A of Form 10-K. c) Changes in Internal Control Over Financial Reporting There were no changes in the Company’s internal control over financial reporting during the Company’s fourth fiscal quarter of 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. * * * 21 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders Helmerich & Payne, Inc. We have audited Helmerich & Payne, Inc.’s internal control over financial reporting as of September 30, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich & Payne, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of September 30, 2008 and 2007 and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended September 30, 2008 of Helmerich & Payne, Inc. and our report dated November 25, 2008 expressed an unqualified opinion thereon. /S/ Ernst & Young LLP Tulsa, Oklahoma November 25, 2008 22 Item 9B. OTHER INFORMATION None. 23 PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE This information (under the captions ‘‘Proposal 1—Election of Directors,’’ ‘‘Committees,’’ ‘‘Corporate Governance’’ and ‘‘Section 16(a) Beneficial Ownership Reporting Compliance’’) is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 4, 2009, to be filed with the Commission not later than 120 days after September 30, 2008. Information required under this item with respect to executive officers under Item 401 of Regulation S-K appears under ‘‘Executive Officers of the Company’’ in Part I of this Form 10-K. The Company has adopted a Code of Ethics applicable to its CEO, CFO and Senior Financial Officers. The text of such Code is located on the Company’s website under ‘‘Corporate Governance.’’ The Company’s Internet address is www.hpinc.com. The Company intends to disclose any amendments to or waivers from its Code of Ethics on its website. Item 11. EXECUTIVE COMPENSATION This information regarding executive compensation (beginning with the caption ‘‘Executive Compensation, Discussion and Analysis’’ and ending with the caption ‘‘Potential Payments Upon Termination’’), as well as director compensation and compensation committee interlocks and insider participation (under the captions ‘‘Director Compensation in Fiscal 2008’’ and ‘‘Compensation Committee Interlocks and Insider Participation’’) is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 4, 2009, to be filed with the Commission not later than 120 days after September 30, 2008. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS This information (under the captions ‘‘Summary of All Existing Equity Compensation Plans,’’ ‘‘Security Ownership of Certain Beneficial Owners’’ and ‘‘Security Ownership of Management’’) is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 4, 2009, to be filed with the Commission not later than 120 days after September 30, 2008. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE This information (under the captions ‘‘Transactions With Related Persons, Promoters and Certain Control Persons’’ and ‘‘Corporate Governance’’) is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 4, 2009, to be filed with the Commission not later than 120 days after September 30, 2008. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES This information (under the caption ‘‘Audit Fees’’) is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 4, 2009, to be filed with the Commission not later than 120 days after September 30, 2008. 24 Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV a) 1. Financial Statements: The following appear in the Company’s Annual Report to Stockholders on the pages indicated below and are incorporated herein by reference: Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Income for the Years Ended September 30, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 70 71 Consolidated Balance Sheets at September 30, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . 72-73 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 75 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76-109 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 Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K to the Securities & Exchange Commission for fiscal 2006, SEC File No. 001-04221. 3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on October 11, 2007, SEC File No. 001-04221. 4.1 Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company’s Form 8-A, dated January 18, 1996, SEC File No. 001-04221. 4.2 Amendment to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company’s Form 8-K filed on December 12, 2005, SEC File No. 001-04221. *10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Company dated March 30, 1990, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. *10.2 Amendment to Consulting Services Agreement between W. H. Helmerich, III and the Company dated December 26, 1990, is incorporated herein by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221. *10.3 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. 25 *10.4 *10.5 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221. Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1999, SEC File No. 001-04221. *10.6 Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. *10.7 Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997. *10.8 Form of Restricted Stock Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1997, SEC File No. 001-04221. *10.9 Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. *10.10 Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001. *10.11 Form of Director Nonqualified Stock Option Agreement for the 2000 Helmerich & Payne, Inc. Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. *10.12 Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.13 Credit Agreement, dated as of July 16, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc., the several lenders from time to time party thereto, and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221. 10.14 First Amendment to Credit Agreement dated July 15, 2003, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 10.15 Second Amendment to Credit Agreement dated May 4, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 26 10.16 Third Amendment to Credit Agreement dated July 13, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2005, SEC File No. 001-04221. 10.17 Fourth Amendment to Credit Agreement dated July 12, 2005, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on July 13, 2005, SEC File No. 001-04221. 10.18 Fifth Amendment to Credit Agreement dated July 11, 2006, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.4 of the Company’s Form 8-K filed on July 11, 2006, SEC File No. 001-04221. 10.19 First Amended and Restated Credit Agreement dated December 18, 2006, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Bank of Oklahoma, National Association is incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on December 20, 2006, SEC File No. 001-04221. 10.20 First Amendment to First Amended and Restated Credit Agreement dated December 17, 2007, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, National Association is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 18, 2007. 10.21 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221. 10.22 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. 10.23 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. 10.24 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. *10.25 Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 9, 2004, SEC File No. 001-04221. 10.26 Shareholders Agreement and Registration Rights Agreement dated July 19, 2004 between Helmerich & Payne International Drilling Co. and Atwood Oceanics, Inc. is incorporated herein by reference to Exhibit 1.1 of the Company’s Amended Schedule 13D filed on July 21, 2004. 10.27 Underwriting Agreement dated October 13, 2004, between Helmerich & Payne International Drilling Co. and various underwriters is incorporated herein by reference to Exhibit 1.1 of the Company’s Form 8-K filed on October 14, 2004, SEC File No. 001-04221. 27 *10.28 Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 6, 2007, SEC File No. 001-04221. *10.29 Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix ‘‘A’’ to the Company’s Proxy Statement on Schedule 14A filed January 26, 2006. *10.30 Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221. 10.31 Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 7, 2006, SEC File No. 001-04221. 10.32 Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to the Company’s Form 8-K filed July 7, 2007, SEC File No. 001-04221. 10.33 Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. 10.34 Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. 13. The Company’s Annual Report to Shareholders for fiscal 2008. 21. List of Subsidiaries of the Company. 23.1 Consent of Independent Registered Public Accounting Firm. 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32. Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Management or Compensatory Plan or Arrangement. 28 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized: SIGNATURES HELMERICH & PAYNE, INC. By /s/ HANS HELMERICH Hans Helmerich, President and Chief Executive Officer Date: November 26, 2008 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated: By /s/ WILLIAM L. ARMSTRONG By /s/ GLENN A. COX William L. Armstrong, Director Date: November 26, 2008 Glenn A. Cox, Director Date: November 26, 2008 By /s/ RANDY A. FOUTCH By /s/ HANS HELMERICH Randy A. Foutch, Director Date: November 26, 2008 Hans Helmerich, Director and CEO Date: November 26, 2008 By /s/ W. H. HELMERICH, III By /s/ PAULA MARSHALL W. H. Helmerich, III, Director Date: November 26, 2008 Paula Marshall, Director Date: November 26, 2008 By /s/ FRANCIS ROONEY By /s/ EDWARD B. RUST, JR. Francis Rooney, Director Date: November 26, 2008 Edward B. Rust, Jr., Director Date: November 26, 2008 By /s/ JOHN D. ZEGLIS By /s/ DOUGLAS E. FEARS John D. Zeglis, Director Date: November 26, 2008 By /s/ GORDON K. HELM Gordon K. Helm (Principal Accounting Officer) Date: November 26, 2008 Douglas E. Fears (Principal Financial Officer) Date: November 26, 2008 29 I, Hans Helmerich, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc. (the ‘‘Company’’); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report; 4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and 5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the Audit Committee of the Company’s Board of Directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting. Date: November 26, 2008 /s/ Hans Helmerich Hans Helmerich President and Chief Executive Officer 30 I, Douglas E. Fears, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc. (the ‘‘Company’’); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report; 4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and 5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the Audit Committee of the Company’s Board of Directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting. Date: November 26, 2008 /s/ Douglas E. Fears Douglas E. Fears Executive Vice President and Chief Financial Officer 31 Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the Annual Report of Helmerich & Payne, Inc. (the ‘‘Company’’) on Form 10-K for the period ended September 30, 2008 as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), Hans Helmerich, as President and Chief Executive Officer of the Company, and Douglas E. Fears, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that: (1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Hans Helmerich /s/ Douglas E. Fears Hans Helmerich President and Chief Executive Officer Date: November 26, 2008 Douglas E. Fears Executive Vice President and Chief Financial Officer Date: November 26, 2008 32 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 the Company’s Form 10-K as well as the Consolidated Financial Statements and related notes thereto. The Company’s future operating results may be affected by various trends and factors, which are beyond the Company’s control. These include, among other factors, fluctuations in oil and natural gas prices, unexpected expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, 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 the Company’s businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends. With the exception of historical information, the matters discussed in Management’s Discussion & Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. The Company cautions that, while it believes such assumptions to be reasonable and makes them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. The Company is including this cautionary statement to take advantage of the ‘‘safe harbor’’ provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 5 of the Company’s Annual Report on Form 10-K are important factors (but 33 not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company. The Company undertakes no duty to update or revise its forward-looking statements based on changes of internal estimates or expectations or otherwise. EXECUTIVE SUMMARY Helmerich & Payne, Inc. is primarily a contract drilling company which owned and operated a total of 224 drilling rigs at September 30, 2008. The Company’s contract drilling segments include the U.S. Land segment in which the Company had 185 rigs, the Offshore segment in which the Company had 9 offshore platform rigs, and the International Land segment in which the Company had 30 rigs at September 30, 2008. As customers pursue more difficult wells employing horizontal and directional drilling to deliver better and more cost-effective reservoir performance in shales and other unconventional plays, the demand for the Company’s FlexRig technology remains strong. In 2008, the Company reported a 25 percent annual increase in operating revenue and a 10 percent annual increase in operating income. RESULTS OF OPERATIONS All per share amounts included in the Results of Operations discussion are stated on a diluted basis. The Company’s net income for 2008 was $461.7 million ($4.34 per share), compared with $449.3 million ($4.27 per share) for 2007 and $293.9 million ($2.77 per share) for 2006. Included in the Company’s net income were after-tax gains from the sale of investment securities of $13.5 million ($0.13 per share) in 2008, $40.2 million ($0.38 per share) in 2007, and $12.3 million ($0.12 per share) in 2006. Net income also includes after-tax gains from the sale of assets of $8.6 million ($0.08 34 per share) in 2008, $26.5 million ($0.25 per share) in 2007 and $4.8 million ($0.04 per share) in 2006. Included in net income in 2008 and 2007 are after-tax gains of $6.5 million ($0.06 per share) and $10.6 million ($0.10 per share), respectively, from involuntary conversion of long-lived assets that sustained significant damage as a result of Hurricane Katrina in 2005. Also included in net income is the Company’s portion of income from its equity affiliate, Atwood Oceanics, Inc. From the equity affiliate, the Company recorded net income of $0.16 per share in 2008, $0.09 per share in 2007 and $0.07 per share in 2006. Consolidated operating revenues were $2,036.5 million in 2008, $1,629.7 million in 2007, and $1,224.8 million in 2006. Over the three-year period, U.S. land revenues increased due to the addition of FlexRigs combined with continued increases in dayrates since 2005. The average number of U.S. land rigs available was 171 rigs in 2008, 134 rigs in 2007 and 96 rigs in 2006. U.S. land rig utilization for the Company was 96 percent in 2008, 97 percent in 2007 and 99 percent in 2006. Revenue in the Offshore segment increased in 2008 after decreasing in 2007. The Company entered into the international offshore market with one rig in 2008. Rig utilization for offshore rigs increased to 75 percent in 2008 compared to 65 percent in 2007 and 69 percent in 2006. International rig revenues increased from 2006 to 2008, due to increases in dayrates although rig utilizations declined in 2008 to 82 percent from 90 percent in 2007 and 2006. Gains from the sale of investment securities were $22.0 million in 2008, $65.5 million in 2007, and $19.9 million in 2006. Interest and dividend income increased to $5.0 million in 2008 from $4.2 million in 2007 after a decrease from $9.8 million in 2006. In 35 2006 and through part of 2007, the Company’s cash position decreased as new FlexRigs were constructed. During 2008, the Company’s available cash increased as overall rig utilization increased and capital expenditures decreased. Direct operating costs in 2008 were $1,086.7 million or 53 percent of operating revenues, compared with $862.3 million or 53 percent of operating revenues in 2007, and $661.6 million or 54 percent of operating revenues in 2006. Depreciation expense was $210.8 million in 2008, $146.0 million in 2007 and $101.6 million in 2006. Included in depreciation are abandonments of equipment of $13.3 million in 2008, $4.1 million in 2007, and $1.7 million in 2006. Depreciation expense, exclusive of the abandonments, increased over the three-year period as the Company placed into service 33 new rigs in 2008, 45 in 2007 and 21 in 2006. Depreciation expense in 2009 is expected to increase from 2008 as the Company plans to place new FlexRigs into service at a pace ranging from two to four per month. (See Liquidity and Capital Resources.) Each year, management performs an analysis of the industry market conditions in each drilling segment. Based on this analysis, management determines if an impairment is required. In 2008, 2007 and 2006, no impairment was recorded. 36 General and administrative expenses totaled $57.1 million in 2008, $47.4 million in 2007, and $51.9 million in 2006. Other general and administrative expenses Stock-based compensation Acceleration of share options Total 2008 $49,603 7,456 — $57,059 2007 (in thousands) $40,391 7,010 — $47,401 2006 $42,121 6,941 2,811 $51,873 The increase in 2008 from 2007 is primarily a result of increases in expenses associated with employee labor and employee benefits due to increases in the number of employees. The decrease in 2007 from 2006 is attributable in part to the Company accelerating the vesting of share options held by a senior executive who retired in fiscal 2006. The decrease is also due to pension expense decreasing $5.6 million in 2007 from 2006. The Pension Plan was frozen and benefit accruals were discontinued effective September 30, 2006, thus reducing the service cost of the Plan. The 2007 decrease was partially offset by increases in employee labor, benefits and operating costs associated with the number of employees increasing. Interest expense was $18.7 million in 2008, $10.1 million in 2007, and $6.6 million in 2006. The interest expense is primarily attributable to the fixed-rate intermediate debt outstanding in each year and advances on the senior credit facility in 2008 and 2007. Capitalized interest was $4.7 million, $9.4 million and $6.1 million in 2008, 2007 and 2006, respectively. All of the capitalized interest is attributable to the rig build program. The higher capitalized interest in 2007 is due to a higher number of new rigs being constructed during that year. 37 The provision for income taxes totaled $255.6 million in 2008, $251.0 million in 2007, and $154.4 million in 2006. Effective income tax rates were 37 percent in 2008, 36 percent in 2007, and 35 percent in 2006. Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets assumes, based on estimates and assumptions, that the Company will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances will be recorded against the deferred tax assets resulting in additional income tax expense in the future. (See Note 3 of the Consolidated Financial Statements for additional income tax disclosures.) On May 21, 2008, the Company acquired a private limited partnership, TerraVici Drilling Solutions (TerraVici) in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets and liabilities of TerraVici were recorded as of the acquisition date, at their respective fair values, and consolidated with the Company’s financial statements. The operations for TerraVici are included with all other non-reportable business segments. TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. The Company acquired TerraVici to complement technology currently used with the FlexRig. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with the Company’s existing 38 capabilities, the Company expects to improve drilling productivity and reduce total well cost to the customer. The Company paid a total purchase price of $12.2 million, including acquisition related fees of $1.2 million. In conjunction with the acquisition, the Company recorded an in-process research and development (IPR&D) charge of $11.1 million in 2008. The IPR&D represents rotary steerable system (RSS) tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. The $11.1 million estimated fair value of the IPR&D was derived using the multi-period excess-earnings method. The terms of the transaction provide for future contingency payments up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met. During 2008, the Company incurred $1.8 million of research and development expenses related to ongoing development of the RSS. The Company anticipates research and development expenses to be approximately $2.5 million in each quarter through June 30, 2009. The following tables summarize operations by reportable operating segment. In an evaluation of its segment reporting, the Company determined that the total of external revenues reported by the three reportable operating segments, U.S. Land, Offshore and International Land, comprised more than 75 percent of total consolidated revenue. As a result, the Real Estate segment previously shown as a reportable segment has been included with all other non-reportable business segments. This change, along with a detailed description of segment operating income, is described more fully in Note 15 to the Consolidated Financial Statements. 39 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 8 A N D 2 0 0 7 2008 2007 % Change U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation (in thousands, except operating statistics) $1,542,038 $1,174,956 756,828 17,599 161,893 587,825 14,024 106,107 Segment operating income $ 605,718 $ 467,000 Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 59,804 24,522 11,393 13,129 $ $ $ 185 96% 47,338 23,573 11,170 12,403 $ $ $ 157 97% 31.2% 28.8 25.5 52.6 29.7 26.3% 4.0 2.0 5.9 17.8 (1.0) Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $75,519 and $59,035 for 2008 and 2007, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007 The Company’s U.S. Land segment operating income increased to $605.7 million in 2008 from $467.0 million in 2007. Improvement in revenue is primarily the result of increased revenue days and increased dayrates for new rigs placed in service during 2008. Rig utilization decreased to 96 percent in 2008 from 97 percent in 2007. At September 30, 2007, the Company had six conventional rigs stacked. The stacked rigs target a deeper well market that softened during the last half of fiscal 2007. At September 30, 2008, two conventional rigs and one highly mobile rig were stacked. The total number of rigs at September 30, 2008 was 185 compared to 157 rigs at September 30, 2007. The increase is due to 28 new FlexRigs having been completed and placed into service. Depreciation includes abandoned equipment of $13.2 million and $2.3 million in 2008 and 2007, respectively. Excluding the abandonment amounts, depreciation in 2008 increased 43.2 percent from 2007 due to the increase in available rigs. 40 Although direct operating expenses increased 28.8 percent from 2007 to 2008, the expense as a percentage of revenue remained constant at 49 percent in 2008 and 50 percent in 2007. Since March 2005, the Company has announced plans to build 127 new FlexRigs for 25 exploration and production companies. Subsequent to September 30, 2008, the Company announced that agreements had been reached with five of the 25 above mentioned exploration and production companies to operate an additional 13 new FlexRigs bringing the total of the new rigs to 140. Eight of these 140 new rigs were contracted for work in International Land operations and the remaining 132 in U.S. Land operations. Each new rig will be operated by the Company under a fixed term contract of at least three years. The drilling services will be performed on a day work contract basis. During 2008, the U.S. Land segment had 29 new FlexRigs placed into service, one of which was completed at the end of fiscal 2007. Through September 30, 2008, 96 of the 132 new FlexRigs with long-term commitments in the U.S. Land segment were placed into service. The Company expects to deliver the remaining 36 new rigs by the end of calendar 2009. As a result of the new FlexRigs added in 2008 and additional rigs scheduled for completion in 2009, the Company anticipates depreciation expense to increase in fiscal 2009. During the fourth quarter of fiscal 2007, the Company’s Rig 178 was lost when the well it was drilling had a blowout. The rig was insured at a value that approximated replacement cost. During 2008, gross insurance proceeds of approximately $8.7 million were received and a gain of approximately $5.0 million was recorded. The Company anticipates settling the insurance claim before the end of the first fiscal quarter of 2009 and expects to receive additional insurance proceeds of less than $0.3 million. 41 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 8 A N D 2 0 0 7 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 2008 2007 % Change (in thousands, except operating statistics) $154,452 104,454 4,452 12,152 $ 33,394 2,442 $ 47,743 $ 29,655 $ 18,088 9 75% $123,148 85,556 4,824 10,687 $ 22,081 2,141 $ 34,469 $ 21,564 $ 12,905 9 65% 25.4% 22.1 (7.7) 13.7 51.2 14.1% 38.5 37.5 40.2 — 15.4 Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $16,330 and $14,328 for 2008 and 2007, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in the Company’s Offshore segment increased 51.2 percent in 2008 from 2007 due to higher activity and a rig beginning work in Trinidad during 2008. Currently, the Company has eight of its nine platform rigs working. The ninth rig is currently under contract and in the yard undergoing capital improvement; it is expected to commence work in the third fiscal quarter of 2009. During the fourth quarter of fiscal 2005, the Company’s Rig 201 was damaged by Hurricane Katrina. The rig was removed from service in the fourth fiscal quarter of 2005 until the fourth fiscal quarter of 2007, when it returned to service. The rig was insured at a value that approximated replacement cost. Insurance proceeds received through fiscal 2007 totaled approximately $19.3 million resulting in a gain of approximately $16.7 million. During 2008, additional insurance proceeds of approximately $5.2 million were received and recorded as 42 a gain. Capital costs to rebuild the rig were capitalized and are being depreciated in accordance with the accounting policy described in Critical Accounting Policies and Estimates. The Company expects to settle this claim early in fiscal 2009 and estimates additional proceeds will be less than $0.1 million. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 8 A N D 2 0 0 7 INTERNATIONAL LAND OPERATIONS (in thousands, except operating statistics) 2008 2007 % Change Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization $328,244 224,683 3,974 29,614 $ 69,973 8,026 $ 37,604 $ 24,489 $ 13,115 30 82% $320,283 188,086 3,236 23,782 $105,179 8,886 $ 31,465 $ 16,708 $ 14,757 27 90% 2.5% 19.5 22.8 24.5 (33.5) (9.7)% 19.5 46.6 (11.1) 11.1 (8.9)% Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $26,431 and $40,113 for 2008 and 2007, respectively. Also excluded are the effects of currency revaluation expense. Rig utilization excludes four FlexRigs completed and ready for delivery at September 30, 2008. Segment operating income for the Company’s International Land segment decreased 33.5 percent from 2007 to 2008. Depreciation and operating income for 2008 were negatively impacted by an adjustment of approximately $5.9 million related to prior years’ depreciation. Rig utilization for international land operations decreased to 82 percent in 2008 from 90 percent in 2007. Direct operating expenses increased in 2008 from 2007 as the international markets experienced labor cost increases, oilfield cost inflation pressures and idle rigs continued to incur operating expenses. As the environment changed in some of the South American countries, the 43 number of rigs working declined to 19 rigs during the second fiscal quarter of 2008 before recovering to 26 rigs working at the end of the fiscal year. The total number of rigs at September 30, 2008 was 30 compared to 27 rigs at September 30, 2007. The increase is due to one new FlexRig being completed and placed into service, four FlexRigs being completed and ready for delivery and the sale of two rigs. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 7 A N D 2 0 0 6 U.S. LAND OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2007 2006 % Change (in thousands, except operating statistics) $1,174,956 587,825 14,024 106,107 $ 467,000 47,338 23,573 11,170 12,403 $ $ $ 157 97% $829,062 398,873 12,807 66,127 $351,255 34,414 $ 22,751 $ 10,250 $ 12,501 113 99% 41.7% 47.4 9.5 60.5 33.0 37.6% 3.6 9.0 (0.8) 38.9 (2.0) Operating statistics for per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $59,035 and $46,098 for 2007 and 2006, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007 and three FlexRigs completed and ready for delivery at September 30, 2006. The Company’s U.S. Land segment operating income increased to $467.0 million in 2007 from $351.3 million in 2006. Improvement in revenue is primarily the result of increased revenue days as the increasing dayrates experienced during 2006 declined or flattened during 2007. Rig utilization decreased to 97 percent in 2007 from 99 percent in 2006. The decrease in rig utilization is primarily due to six conventional rigs being stacked by September 30, 2007. Average rig expense per day increased 9.0 percent as the demand for 44 rig personnel and services continued to create cost pressures. The total number of rigs at September 30, 2007 was 157 compared to 113 rigs at September 30, 2006. The increase is due to 45 new FlexRigs being completed and placed into service, one rig completed and ready for delivery, the sale of one conventional rig in June 2007 and the loss of one rig in a well blowout fire in August 2007. Depreciation in 2007 increased 60.5 percent from 2006 due to the increase in available rigs. C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 7 A N D 2 0 0 6 OFFSHORE OPERATIONS Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization 2007 2006 % Change (in thousands, except operating statistics) $123,148 85,556 4,824 10,687 $ 22,081 2,141 $ 34,469 $ 21,564 $ 12,905 9 65% $154,543 105,133 6,144 11,401 $ 31,865 2,743 $ 38,728 $ 24,041 $ 14,687 9 69% (20.3)% (18.6) (21.5) (6.3) (30.7) (21.9)% (11.0) (10.3) (12.1) (5.8) Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $14,328 and $18,924 for 2007 and 2006, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense. Segment operating income in the Company’s Offshore segment decreased 30.7 percent from 2006 to 2007. Operator decisions to go on standby caused revenue and expenses to decline after the segment experienced increased activity in 2006 following the hurricanes in 2005. 45 C O M PA R I S O N O F T H E Y E A R S E N D E D S E P T E M B E R 3 0 , 2 0 0 7 A N D 2 0 0 6 INTERNATIONAL LAND OPERATIONS (in thousands, except operating statistics) 2007 2006 % Change Operating revenues Direct operating expenses General and administrative expense Depreciation Segment operating income Operating Statistics: Revenue days Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at end of period Rig utilization $320,283 188,086 3,236 23,782 $105,179 8,886 $ 31,465 $ 16,708 $ 14,757 27 90% $230,829 155,766 3,274 19,471 $ 52,318 8,812 $ 23,404 $ 14,806 $ 8,598 27 90% 38.8% 20.7 (1.2) 22.1 101.0 0.8% 34.4 12.8 71.6 — — Operating statistics of per day revenue, expense and margin do not include reimbursements of ‘‘out-of-pocket’’ expenses of $40,113 and $23,992 for 2007 and 2006, respectively. Also excluded are the effects of currency revaluation expense. Segment operating income for the Company’s International Land segment increased 101.0 percent from 2006 to 2007 due to day rate increases in several foreign markets with the most significant increase occurring in Venezuela. Segment operating income also benefited from a new FlexRig being added to the international fleet at the end of fiscal 2006. Rig utilization for international land operations averaged 90 percent in both 2007 and 2006. Direct operating expenses increased in 2007 primarily due to inflationary pressures in the oil service sector and contractual cost increases under the Company’s drilling contracts with operators. LIQUIDIT Y AND CAPITAL RESOURCES The Company’s capital spending was $705.6 million in 2008, $894.2 million in 2007, and $528.9 million in 2006. Net cash provided from operating activities for those same periods was $610.8 million in 2008, $561.1 million in 2007 and $296.4 million in 2006. The Company’s 2009 capital spending estimate is 46 approximately $900 million, an increase from the $706 million incurred during 2008. Included in the estimate is the construction of new FlexRigs. Construction of the contracted new FlexRigs is expected to be completed by the end of calendar year 2009. Historically, the Company has financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, the Company will either borrow from an available unsecured line of credit or, if market conditions are favorable, sell portfolio securities. Likewise, if the Company is generating excess cash flows, the Company may invest in short-term investments. In 2006, the Company purchased $8.6 million of portfolio securities and $139.8 million of short-term investments. The Company manages a portfolio of marketable securities that, at the close of fiscal 2008, had a market value of $384.0 million. The Company’s investments in Atwood Oceanics, Inc. (‘‘Atwood’’) and Schlumberger, Ltd. made up 95 percent of the portfolio’s market value on September 30, 2008. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding the Company’s equity-method investment in Atwood and investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the Company’s balance sheet. The Company currently owns 8,000,000 shares or approximately 12.5 percent of the outstanding shares of Atwood. The Company generated cash proceeds from the sale of portfolio securities of $25.5 million in 2008, $73.4 million in 2007, and $28.2 million in 2006. 47 The following table reconciles cash proceeds from the sale of portfolio securities stated above to proceeds from sale of investments shown in the Consolidated Statements of Cash Flows in the Company’s Consolidated Financial Statements: 2008 Proceeds from the sale of portfolio securities $25,507 Sales with a trade date in current fiscal year but cash received in subsequent fiscal year Proceeds from the sale of short-term investments Proceeds from sale of investments per Consolidated — — 2007 (in thousands) $ 73,405 6,093 48,321 2006 $ 28,245 (6,093) 91,563 Statements of Cash Flows $25,507 $127,819 $113,715 In 2008, proceeds were from the sale of 170,000 shares of Schlumberger, Ltd. and all other available-for-sale securities the Company owned. In 2007, proceeds were primarily from the sale of 1,012,500 shares of Schlumberger, Ltd. Proceeds in both years were primarily used to fund capital expenditures. In 2006, proceeds were primarily from the sale of 230,000 shares of Schlumberger, Ltd. Proceeds were primarily used to repurchase shares of Company common stock and to fund capital expenditures. The Company has historically been a long-term holder of investment securities. However, circumstances may arise, such as significant capital spending requirements or the opportunity to repurchase Company common stock, that were not previously contemplated. During 2006 and 2007, the Company purchased 2,007,100 shares of Company common stock at an aggregate cost of $46.0 million. The Company’s proceeds from asset sales totaled $22.9 million in 2008, $51.6 million in 2007 and $11.8 million in 2006. In 2008, two international land rigs were sold generating $13.0 million in proceeds. 48 Income from asset sales in 2008 totaled $13.5 million. In 2007, one U.S. land rig and two offshore rigs were sold generating $36.7 million in proceeds. Income from asset sales in 2007 totaled $41.7 million. In 2006, one U.S. land rig was sold generating $4.8 million in proceeds. Income from asset sales in 2006 totaled $7.5 million. The rigs sold in each year were idle at the time of the sales and, with the Company’s emphasis on FlexRig technology, the Company took advantage of the opportunity to sell older rigs. In each year the Company also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business. In the fourth fiscal quarter of 2006, the Company received approximately $3.0 million in insurance proceeds from damages sustained to the Company’s offshore Rig 201 during Hurricane Katrina. In 2008 and 2007, the Company received additional insurance proceeds of approximately $5.3 million and $16.3 million, respectively. During the fourth quarter of fiscal 2007, the Company’s Rig 178 was lost when the well it was drilling had a blowout. During 2008, the Company received gross insurance proceeds of approximately $8.7 million in connection with the loss of Rig 178. In conjunction with removing the net book value of damaged equipment lost in both incidents, the Company recorded a gain from involuntary conversion of approximately $10.2 million in 2008 and $16.7 million in 2007. The proceeds, shown in the Consolidated Statements of Cash Flows under investing activities, were used to rebuild Rig 201 and replace Rig 178. The costs for both rigs were capitalized with Rig 201 returning to work in the fourth fiscal quarter of 2007 and the replacement rig returning to work in 2008. Between March 2005 and the end of fiscal 2008, the Company announced contracts to build and operate 127 new FlexRigs for 25 49 exploration and production companies. Subsequent to September 30, 2008, the Company announced that agreements had been reached with five exploration and production companies to operate an additional 13 of the 25 above mentioned new FlexRigs, bringing the total of the new rigs to 140. Eight of these 140 new rigs were contracted for work in International Land operations and the remaining 132 in U.S. Land operations. Each agreement has a minimum fixed contract term of at least three years. The drilling services are performed on a day work contract basis. Through fiscal 2008, 102 rigs were completed for delivery, and 98 of the 102 rigs began field operations by September 30, 2008. The remaining rigs are expected to be completed by the end of the calendar year 2009. The total estimated construction cost of all 140 rigs is currently $2.2 billion, of which over 70 percent was spent by the end of fiscal 2008. The Company has $175 million of intermediate-term unsecured debt obligations with staged maturities from August, 2009 to August, 2014. The annual average interest rate through maturity will be 6.50 percent. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. The Company has an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility. The Company has the option to borrow at the prime rate for maturities of less than 30 days but anticipates the majority of all of the borrowings over the life of the new facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). The Company pays 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 the Company’s total debt to total capitalization. The LIBOR spread ranges from .30 percent to 50 .45 percent depending on the ratio. Based on the ratio at the close of the fiscal year, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. Financial covenants in the facility require the Company to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The facility contains additional terms, conditions, and restrictions that the Company believes are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. The advances bear interest ranging from 2.84 percent to 4.06 percent. At September 30, 2008, the Company had three letters of credit totaling $25.9 million under the facility and had borrowed $325 million against the facility with $49.1 million remaining available to borrow. Subsequent to September 30, 2008, the Company reduced the debt by $35 million and had $84.1 million available to borrow. At September 30, 2008, the Company was in compliance with all debt covenants. The Company also has an agreement with a single bank for an unsecured line of credit for $5 million. Pricing on the amended line of credit is prime minus 1.75 percent. The covenants and other terms and conditions are similar to the aforementioned senior credit facility except that there is no commitment fee. At September 30, 2008, the Company had no outstanding borrowings against this line. As of September 30, 2008, the Company had an outstanding, secured note payable to a bank in Argentina totaling $1.7 million denominated in a foreign currency. The interest rate of the note was 16 percent with a one year maturity. The note and interest were paid in full subsequent to September 30, 2008. 51 At September 30, 2008, the Company had unsecured letters of credit totaling $6.3 million and a $0.7 million secured letter of credit, both of which were used to obtain surety bonds for the international operations. The Company has initiated discussions with lenders to obtain an additional credit facility. The Company anticipates the amount of the facility to range from $100 million to $150 million and does not expect significant difficulties in obtaining additional financing. However, because of the current conditions of the credit markets there can be no assurance that any new financing will be on equal or better terms than those of the current debt agreement. At September 30, 2008, the Company had 118 rigs completed with contracts under fixed term, including 102 covering the FlexRig new-build projects. The duration of the fixed term contracts are from twelve months to seven years, with some expiring in fiscal 2009. The contracts provide for termination at the election of the customer, with an early termination payment to be paid to the Company if a contract is terminated prior to the expiration of the fixed term. The recent economic slowdown, including the decrease in oil prices and deterioration in the credit markets is expected to have an effect on customer spending. While the Company’s customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, could become unable to meet its obligations and may exercise its early termination election and not be able to pay the early termination fee. Were this to happen, the Company’s future revenue and operating results would be negatively impacted. At this time, the Company is unable to predict if this will occur in 2009. 52 The Company’s operating cash requirements and estimated capital expenditures, including rig construction, for fiscal 2009 will be funded through current cash, cash provided from operating activities, funds available under the current credit facilities, funds available under any new credit facility and, possibly, sales of available-for-sale securities. Current ratios were 2.2 at both September 30, 2008 and 2007. The long-term debt to total capitalization ratio was 17 percent and 20 percent at September 30, 2008 and 2007, respectively. The decrease is due to equity increasing, primarily from earnings. During 2008, the Company paid a dividend of $0.185 per share, or a total of $19.9 million, representing the 36th consecutive year of dividend increases. STOCK PORTFOLIO HELD BY THE COMPANY September 30, 2008 Atwood Oceanics, Inc. Schlumberger, Ltd. Other Total Number of Shares Cost Basis Market Value (in thousands, except share amounts) 8,000,000 967,500 $104,910 $291,200 7,685 12,369 75,552 17,286 $124,964 $384,038 MATERIAL COMMITMENTS The Company has no off balance sheet arrangements other than operating leases discussed below. The Company’s contractual 53 obligations as of September 30, 2008, are summarized in the table below: Payments due by year Contractual Obligations Total 2009 2010 2011 2012 2013 After 2013 Long-term debt (a) $500,000 $ 25,000 $ — $325,000 $75,000 $ — $75,000 Operating leases (b) 29,875 5,835 4,158 2,595 2,543 2,526 12,218 Purchase obligations (b) 270,713 270,713 — — — — — Total Contractual Obligations $800,588 $301,548 $4,158 $327,595 $77,543 $2,526 $87,218 (in thousands) (a) See Note 2 ‘‘Notes Payable and Long-term Debt’’ to the Company’s Consolidated Financial Statements. (b) See Note 14 ‘‘Commitments and Contingencies’’ to the Company’s Consolidated Financial Statements. The above table does not include obligations for the Company’s pension plan and amounts recorded for uncertain tax positions. In 2008, the Company contributed $3.1 million to the pension plan. Based on current information available from plan actuaries, the Company does not anticipate contributions to the plan will be required in 2009. The Company does expect to make discretionary contributions to fund distributions of at least $5.0 million in 2009. However, due to the decline in the fair value of pension plan assets during 2008 and the current adverse conditions in the equity, debt and global markets, it is possible that contributions will be greater than expected. Future contributions beyond 2009 are difficult to estimate due to multiple variables involved. At September 30, 2008, the Company had $8.1 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 3 to the Consolidated Financial Statements. 54 CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Company’s Consolidated Financial Statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. On an on-going basis, the Company evaluates the estimates, including those related to long-lived assets and accrued insurance losses. The estimates are based on historical experience and on various other assumptions that the Company believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies used in the Company’s 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. The Company accounts for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets. Depreciation is determined based on 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 the Company’s estimates and assumptions related to depreciation. Management believes that these estimates have been materially accurate in the past. For the years presented in this report, no significant changes were made to the determinations 55 of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations. Impairment of Long-lived Assets The Company’s management assesses the potential impairment of its long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that trigger such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. The fair value of drilling rigs is determined based on quoted market prices, if available. Otherwise it is determined based upon estimated discounted future cash flows and rig utilization. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics due to lower industry utilization. Use of different assumptions could result in an impairment charge different from that reported. Goodwill and Indefinite-Lived Intangibles Goodwill represents the excess of cost over the fair market value of net assets acquired in business combinations. Indefinite-lived intangibles are comprised of 56 trademarks. At September 30, 2008, goodwill and other indefinite- lived intangibles totaled $1.9 million, which arose from the acquisition of TerraVici. The Company reviews goodwill and other intangibles at least annually for impairment or more frequently if indicators of impairment warrant additional analysis. In order to test for impairment, goodwill acquired is assigned to reporting units that are expected to benefit from the synergies of the related business combination. The Company determines reporting units pursuant to FAS No. 142. Goodwill is evaluated for impairment by first comparing management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of a reporting unit exceeds its fair value, a computation of the implied fair value of goodwill is compared with its related carrying value. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized. The Company’s acquisition-related intangible assets are comprised of non-compete agreements that are amortized over periods ranging from three to five years on a straight-line basis. Self-Insurance Accruals The Company self-insures a significant portion of expected losses relating to worker’s compensation, general liability, employer’s liability, and auto liabilities. Generally, deductibles are $1 million or $2 million per occurrence depending on whether a claim occurs inside or outside of the United States. For rig and equipment property, the Company self-insures $1 million per occurrence, as well as 10 percent of the estimated replacement cost on offshore rigs and 30 percent of the estimated replacement cost of its land rigs and equipment. The Company purchased an aggregate limit of $100 million of ‘‘named wind storm’’ coverage and self- insures 10 percent of that limit as well as a $3.5 million deductible. The Company maintains certain other insurance coverage with 57 deductibles as high as $5 million. Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon the Company’s estimates of the aggregate liability for claims incurred, and, using adjuster’s estimates, the Company’s historical loss experience or estimation methods that are believed to be reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense and related liabilities. Pension Costs and Obligations The Company’s pension benefit costs and obligations are dependent on various actuarial assumptions. The Company makes assumptions relating to discount rates, rate of compensation increase, and expected return on plan assets. The Company’s discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was raised from 6.25 percent to 7.25 percent as of September 30, 2008 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 58 from future periods. The Company anticipates pension expense in 2009 to increase from 2008 by an estimated $1.3 million. Stock-Based Compensation Historically, the Company has granted stock-based awards to key employees and non-employee directors as part of their compensation. The Company estimates the fair value of all stock option awards as of the date of grant by applying the Black- Scholes option-pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and risk-free interest rate. Expected volatilities were estimated using the historical volatility of the Company’s stock, based upon the expected term of the option. The Company considers 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 based on the closing price of the Company’s common stock on the date of grant. The Company amortizes the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2008, unrecognized compensation cost related to 59 unvested restricted stock was $3.6 million. The cost is expected to be recognized over a weighted-average period of 2.5 years. Revenue Recognition Revenues and expenses for day work contracts are recognized daily as the work progresses. For certain contracts, payments are received that are contractually designated for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. NEW ACCOUNTING STANDARDS In June, 2006, the Financial Accounting Standards Board (‘‘FASB’’) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (‘‘FIN 48’’). This interpretation prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation was adopted by the Company October 1, 2007. The net impact to the Company of the cumulative effect of adopting FIN 48, as more fully discussed in Note 3 to the Consolidated Financial Statements, was a decrease of approximately $5.0 million in retained earnings. 60 In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and will be adopted by the Company beginning in the first quarter of fiscal 2009. Although the Company will continue to evaluate the application of SFAS No. 157, management does not currently believe adoption will have a material impact on the Company’s financial condition or operating results. In February 2008, the FASB issued FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2). FSP 157-2 amends SFAS No. 157, Fair Value Measurements, to delay the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) and will be adopted by the Company beginning in the first quarter of fiscal 2010. In October 2008, the FASB issued FSP No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (FSP 157-3), to clarify the application of SFAS 157 in inactive markets for financial assets. FSP 157-3 became effective upon issuance. In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis and, with a few exceptions, is 61 irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. At the effective date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. The Company has elected not to adopt the elective provisions of SFAS No. 159. In April 2008, the FASB issued FSP SFAS No. 142-3, Determining the Useful Life of Intangible Assets (FSP SFAS 142-3). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. This FSP is effective for fiscal years beginning after December 15, 2008, and interim periods within those years. This FSP must be applied prospectively to intangible assets acquired after the effective date. Accordingly, the Company will adopt FSP SFAS 142-3 in fiscal year 2010. In June 2008, the FASB issued Staff Position (FSP) EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, to clarify that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method in SFAS No. 128, Earnings per 62 Share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008. The Company is currently evaluating FSP EITF 03-6-1 to determine the impact, if any, on the Consolidated Financial Statements. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51. Both of these standards are effective for financial statements issued for fiscal years beginning after December 15, 2008. SFAS No. 141(R) will be applied prospectively to business combinations occurring after the effective date. Earlier application is prohibited. The Company is currently evaluating the potential impact of adopting SFAS No. 160 but does not expect its adoption to have a significant impact on the Consolidated Financial Statements. In June 2007, the FASB ratified EITF Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). EITF 06-11 requires that the income tax benefits received on dividends or dividend equivalents paid to employees holding equity-classified shares be recorded as additional paid-in capital when the dividends or dividend equivalents are charged to retained earnings pursuant to SFAS No. 123(R). This EITF is applied prospectively and is effective for fiscal years beginning after December 15, 2007, and interim periods within those years. EITF 06-11 also requires the disclosure of any change in accounting policy for income tax benefits of dividends or dividend equivalents on share-based payment awards as a result of adoption. The Company will adopt EITF 06-11 beginning in the first quarter of fiscal 2009 and does not expect its adoption to have a significant impact on the Consolidated Financial Statements. 63 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Foreign Currency Exchange Rate Risk The Company has operations in several South American countries and Africa. With the exception of Argentina and Venezuela, the Company’s exposure to currency valuation losses is usually immaterial due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars. In Argentina, the Company’s exposure is limited by the fact that the exchange rate between the U.S. dollar and the Argentine peso has stayed within a narrow range for the last seven years. On January 1, 2008, the Venezuelan government changed the official Venezuelan currency from the bolivar to the bolivar fuerte (Bsf ) (2150 bolivars equals 2.15 bolivar fuerte). The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of Bsf receivable balances and Bsf cash balances. In Venezuela, approximately 60 percent of the Company’s billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1,600 bolivares to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars. On October 1, 2003, in compliance with applicable regulations, the Company submitted a request to the Venezuelan government seeking permission to convert existing bolivar balances into U.S. dollars. In January 2004, the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars and the remittance of $8.8 million U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S. based parent. This was the first dividend remitted under the new regulation. On January 16, 2006, a dividend 64 of $6.5 million U.S. dollars was paid to the U.S. based parent. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation has been reduced by these amounts. On July 22, 2008, the Company submitted applications with the Venezuelan government requesting the approval to convert bolivar fuerte cash balances to U.S. dollars. When and if the Company receives approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation. While the Company has been successful in obtaining government approval for conversion of bolivars to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then bolivar fuerte cash balances would increase and expose the Company to increased risk of devaluation. As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of Bsf receivable and cash balances. The exchange rate per U.S. dollar increased to 2150 bolivares (2.15 Bsf ) during 2005 from 1920 bolivares at September 30, 2004. As a result of the 12 percent devaluation of the bolivar during fiscal 2005 (from September 2004 through August 2005), the Company experienced total devaluation losses of $0.6 million during that same period. Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Even 65 though Venezuela continues to operate under the exchange controls in place and the Venezuelan Bsf exchange rate is fixed at 2.15 Bsf to one U.S. dollar, the exact amount and timing of devaluation is uncertain. At September 30, 2008, the Company had a $43.4 million cash balance denominated in Bsf included in the balance sheet and exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2009 balance sheet components are similar to fiscal 2008 and if a 10 percent to 30 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $7.0 million to $18.0 million. The Company has an agreement with the Venezuelan state petroleum company whereby a portion of the Company’s dollar-based invoices are paid in U.S. dollars. There is no guarantee as to how long this arrangement will continue. Were this agreement to end, the Company would revert to receiving all payments in Bsf and thus increase Bsf cash balances and exposure to devaluation. The Venezuelan subsidiary has received notification from PDVSA that reimbursement of U.S. dollar invoices previously paid in Bsf will be made only when supporting documentation has been approved. The supporting documentation has been delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $46.3 million. The Company is unable to determine the timing of when payment will be received. Credit Risk The Company derives its revenue in Venezuela from PDVSA. At September 30, 2008, the Company had a net receivable from PDVSA of $65.5 million of which $5.2 million was 90 days 66 old or older. At November 1, 2008, such receivable balance had decreased to approximately $63.9 million, of which approximately $13.5 million was 90 days old or older. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than those of other customers in international countries in which the Company has drilling operations. Commodity Price Risk The demand for contract drilling services is a result of exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their appetite for such spending is driven by their cash flow and financial strength, which is very dependent on, among other things, crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile and very difficult to predict. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. 67 In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The recent deterioration in the credit and capital markets could 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 the Company’s operations. The prices for drilling rig components have experienced increases in the last year. While these materials have generally been available to the Company at acceptable prices, there is no assurance the prices will not vary significantly in the future. The Company attempts to secure favorable prices through advanced ordering and purchasing, but future fluctuations in market conditions causing increased prices in materials and supplies could impact future operating costs adversely. Interest Rate Risk The Company’s interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from its commercial banks. The Company has reduced the impact of fluctuations in interest rates by maintaining a portion of its debt portfolio in fixed-rate debt. At September 30, 2008, the amount of the Company’s fixed-rate debt was approximately 35 percent of total debt. The following tables provide information as of September 30, 2008 and 2007 about the Company’s interest rate risk sensitive instruments: I N T E R E S T R AT E R I S K A S O F S E P T E M B E R 3 0 , 2 0 0 8 (dollars in thousands) 2009 2010 2011 2012 2013 After 2013 Total Fair Value 9/30/08 Fixed Rate Debt Average Interest Rate Variable Rate Debt $ Average Interest Rate (a) $25,000 $ 5.9% — $ — — $ — — $75,000 — 6.5% — $75,000 — 6.6% $175,000 $198,000 6.5% — $325,000 — — $ — — — — — $325,000 (a) — $325,000 (a) Advances bear interest rates ranging from 2.84% to 4.06% 68 I N T E R E S T R AT E R I S K A S O F S E P T E M B E R 3 0 , 2 0 0 7 (dollars in thousands) 2008 2009 2010 2011 2012 After 2012 Total Fair Value 9/30/07 Fixed Rate Debt Average Interest Rate Variable Rate Debt $ $ — $25,000 $ — $ — $75,000 $75,000 $175,000 $182,269 — 5.9% — — 6.5% 6.6% 6.5% — $ — $ — $270,000 $ — $ — $270,000 $270,000 Average Interest Rate (a) — — — — — — (a) (a) Advances bear interest rates ranging from 5.48% to 6.15% Equity Price Risk On September 30, 2008, the Company had a portfolio of securities with a total market value of $384.0 million. The total market value of the portfolio of securities was $457.5 million at September 30, 2007. The Company’s investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up 95 percent of the portfolio’s market value at September 30, 2008. Although the Company sold portions of its positions in Schlumberger in 2008, 2007 and 2006, the Company makes no specific plans to sell securities, but rather sells securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the market value of the Company’s holdings. Except for the Company’s holdings in its equity affiliate, Atwood Oceanics, Inc., and investments in limited partnerships carried at cost, the portfolio is recorded at fair value on its balance sheet with changes in unrealized after-tax value reflected in the equity section of its balance sheet. At November 20, 2008, the total market value of the portfolio of securities had declined to approximately $175 million. Currently, the fair value exceeds the cost of the investments and, as such, impairment of the investments is not expected during the first fiscal quarter of 2009. The Company continues to monitor the fair market value of the investments but is unable to predict future market volatility and any potential impact to the Consolidated Financial Statements. 69 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, 2008 and 2007, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2008. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2008, in conformity with U.S. generally accepted accounting principles. As explained in Note 1 to the consolidated financial statements, effective October 1, 2007, the Company adopted FASB Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes,’’ an Interpretation of FASB Statement No. 109. 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, 2008, 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 25, 2008 expressed an unqualified opinion thereon. E R N S T & Y O U N G L L P Tulsa, Oklahoma November 25, 2008 70 Consolidated Statements of Income Years Ended September 30, 2008 2007 2006 OPERATING REVENUES Drilling – U.S. Land Drilling – Offshore Drilling – International Land Other OPERATING COSTS AND EXPENSES Operating costs, excluding depreciation Depreciation Research and development Acquired in-process research and development General and administrative Gain from involuntary conversion of long-lived assets Income from asset sales Operating income Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Income before income taxes and equity in income of affiliate Income tax provision Equity in income of affiliate net of income taxes NET INCOME Earnings per common share: Basic Diluted Average common shares outstanding (in thousands): Basic Diluted The accompanying notes are an integral part of these statements. (in thousands, except per share amounts) $1,542,038 $ 1,174,956 $ 829,062 154,452 328,244 11,809 123,148 320,283 11,271 154,543 230,829 10,379 2,036,543 1,629,658 1,224,813 1,086,666 210,766 862,254 146,042 1,833 11,129 57,059 (10,236) (13,490) — — 47,401 (16,661) (41,697) 661,563 101,583 — — 51,873 — (7,492) 1,343,727 997,339 807,527 692,816 632,319 417,286 5,038 (18,689) 21,994 (1,230) 7,113 699,929 255,557 17,366 4,234 (10,126) 65,458 (1,532) 58,034 690,353 250,984 9,892 9,834 (6,644) 19,866 639 23,695 440,981 154,391 7,268 $ 461,738 $ 449,261 $ 293,858 $ $ 4.43 4.34 $ $ 4.35 4.27 $ $ 2.81 2.77 104,284 106,424 103,338 105,128 104,658 106,091 71 Consolidated Balance Sheets ASSETS CURRENT ASSETS: September 30, 2008 2007 (in thousands) Cash and cash equivalents $ 121,513 $ 89,215 Accounts receivable, less reserve of $1,331 in 2008 and $2,957 in 2007 Inventories Deferred income taxes Prepaid expenses and other Total current assets 462,833 33,098 21,939 51,264 690,647 339,819 29,145 11,559 29,226 498,964 INVESTMENTS 199,266 223,360 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment Construction in progress Real estate properties Other Less-Accumulated depreciation Net property, plant and equipment OTHER ASSETS TOTAL ASSETS The accompanying notes are an integral part of these statements. 3,263,818 2,651,680 279,422 60,811 150,200 3,754,251 1,072,000 2,682,251 214,642 59,467 131,482 3,057,271 904,655 2,152,616 15,881 10,429 $3,588,045 $2,885,369 72 LIABILITIES AND SHAREHOLDERS’ EQUITY September 30, CURRENT LIABILITIES: Accounts payable Accrued liabilities Notes payable Long-term debt due within one year Total current liabilities NONCURRENT LIABILITIES: Long-term debt Deferred income taxes Other Total noncurrent liabilities SHAREHOLDERS’ EQUITY: Common stock, $.10 par value, 160,000,000 shares authorized, 107,057,904 shares issued and outstanding Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Accumulated other comprehensive income Less treasury stock, 1,835,483 shares in 2008 and 3,572,961 shares in 2007, at cost Total shareholders’ equity 2008 2007 (in thousands, except share data and per share amounts) $ 153,851 $ 124,556 128,373 1,733 25,000 308,957 475,000 479,963 58,651 1,013,614 10,706 — 169,497 2,082,518 38,407 2,301,128 35,654 2,265,474 102,056 — — 226,612 445,000 363,534 34,707 843,241 10,706 — 143,146 1,645,766 75,885 1,875,503 59,987 1,815,516 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $3,588,045 $2,885,369 The accompanying notes are an integral part of these statements. 73 Consolidated Statements of Shareholders’ Equity Common Stock Shares Amount Additional Paid-In Capital Retained Earnings Unearned Compensation Accumulated Other Comprehensive Income (Loss) Shares Treasury Stock Amount Total Balance, September 30,2005 107,058 $10,706 $106,944 $ 939,380 $(134) $47,544 3,189 $(25,202) $1,079,238 (in thousands, except per share amounts) Comprehensive Income: Net income Other comprehensive income: Unrealized gains on available-for-sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Reversal of unearned compensation upon adoption of SFAS123(R) Cash dividends ($.1725 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $10.2 million Repurchase of common stock Stock-based compensation Balance, September30, 2006 Comprehensive Income: Net income Other comprehensive income (loss): Unrealized losses on available-for-sale securities, net Minimum pension liability adjustment, net Total other comprehensive gain Total comprehensive income Cash dividends ($.18 per per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $1.5 million Repurchase of common stock Stock-based compensation Balance, September 30, 2007 Adjustment to initially apply FASB Interpretation No. 48 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 (net of $4.1 million income tax) Total other comprehensive loss Total comprehensive income Capital adjustment of equity investee Cash dividends ($.185 per share) Exercise of stock options Tax benefit of stock-based awards, including excess tax benefits of $24.9 million Treasury stock issued for vested restricted stock Stock-based compensation Balance, September30, 2008 107,058 10,706 107,058 10,706 (66) 6,019 12,851 9,752 135,500 (1,156) 1,792 7,010 143,146 1,669 (9,740) 27,022 (56) 7,456 The accompanying notes are an integral part of these statements. 74 293,858 17,591 4,510 134 10 (68) (18,111) (1,335) 6,353 293,858 17,591 4,510 22,101 315,959 — (18,111) 12,372 1,215,127 — 69,645 3,189 1,325 (30,169) 12,851 (30,169) 9,752 (49,086) 1,381,892 449,261 (18,622) (2,930) 9,170 (298) 4,958 449,261 (2,930) 9,170 6,240 455,501 (18,622) 3,802 1,645,766 — 75,885 3,573 682 (15,859) 1,792 (15,859) 7,010 (59,987) 1,815,516 (5,048) 461,738 (19,938) (30,863) (6,615) (1,735) 24,277 (5,048) 461,738 (30,863) (6,615) (37,478) 424,260 1,669 (19,938) 14,537 27,022 107,058 $10,706 $169,497 $2,082,518 $ — $38,407 (3) 56 — 7,456 1,835 $(35,654) $2,265,474 Consolidated Statements of Cash Flows Years Ended September 30, 2008 2007 2006 (in thousands) $ 461,738 $ 449,261 $ 293,858 OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation Provision for bad debt Equity in income of affiliate before income taxes Stock-based compensation Gain on sale of investment securities Gain from involuntary conversion of long-lived assets Income from asset sales Acquired in-process research and development Deferred income tax expense Other Change in assets and liabilities: Accounts receivable Inventories Prepaid expenses and other Accounts payable Accrued liabilities Deferred income taxes Other noncurrent liabilities Net cash provided by operating activities INVESTING ACTIVITIES: Capital expenditures Acquisition of business, net of cash acquired Proceeds from asset sales Insurance proceeds from involuntary conversion Purchase of investments Proceeds from sale of investments Net cash used in investing activities (655,335) (698,570) FINANCING ACTIVITIES: Repurchase of common stock Increase (decrease) in notes payable Decrease in long-term debt Proceeds from line of credit Payments on line of credit Increase (decrease) in bank overdraft Dividends paid Proceeds from exercise of stock options Excess tax benefit from stock-based compensation Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period The accompanying notes are an integral part of these statements. 75 — 1,733 — 3,550,000 (3,495,000) — (19,333) 14,537 24,868 76,805 32,298 89,215 (17,621) (3,721) (25,000) 1,490,000 (1,220,000) (17,430) (18,638) 3,802 1,473 192,865 55,362 33,853 89,215 $ 121,513 $ 210,766 704 (28,009) 7,456 (21,864) (10,236) (13,490) 11,129 117,998 — (127,992) (3,953) (25,602) (15,652) 28,214 11,593 8,028 610,828 (705,635) (12,041) 22,908 13,926 — 25,507 146,042 1,030 (15,954) 7,010 (65,320) (16,661) (41,697) — 82,294 1,000 (53,773) (2,980) (18,606) 73,780 5,299 6,107 4,235 561,067 (894,214) — 51,568 16,257 — 127,819 101,583 250 (11,723) 9,752 (19,730) — (7,492) — 3,504 (987) (120,740) (4,852) 372 (11,064) 55,112 4,490 4,057 296,390 (528,905) — 11,778 2,970 (148,440) 113,715 (548,882) (28,407) 3,721 — — — 17,430 (17,712) 12,372 10,189 (2,407) (254,899) 288,752 $ 33,853 Notes to Consolidated Financial Statements NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and its wholly-owned subsidiaries. Fiscal years of the Company’s foreign operations end on August 31 to facilitate reporting of consolidated results. There were no significant intervening events which materially affected the financial statements. BASIS OF PRESENTATION Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Specifically, as more fully described in Note 15, the Real Estate segment previously shown separately has been included with all other non-reportable business segments. FOREIGN CURRENCIES The Company’s functional currency for all its foreign subsidiaries is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the year. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars are included in direct operating costs. Gains and losses resulting from foreign currency transactions are also included in current results of operations. Aggregate foreign currency remeasurement and transaction gains included in direct operating costs totaled $1.0 million in 2007 and losses included in direct operating costs totaled $1.6 million and $0.3 million in 2008 and 2006, respectively. USE OF ESTIMATES The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-50 years; and other, 3-33 years). Depreciation in the Consolidated Statements of Income includes abandonments of $13.3 million, $4.1 million and $1.7 million for 2008, 2007 and 2006, respectively. The Company charges the cost of maintenance and repairs to direct operating cost, while betterments and refurbishments are capitalized. 76 CAPITALIZATION OF INTEREST The Company capitalizes interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for 2008, 2007, and 2006 was $4.7 million, $9.4 million, and $6.1 million, respectively. VALUATION OF LONG-LIVED ASSETS The Company periodically evaluates the carrying value of long-lived assets to be held and used, including intangible assets, when events or circumstances warrant such a review. Changes that could trigger such an assessment may include a significant decline in revenue or cash margin per day, extended periods of low rig utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts, and/or overall general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. ACQUISITIONS The Company accounts for acquired businesses using the purchase method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to acquired in-process research and development are expensed at the date of acquisition. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact results of operations. Accordingly, for significant items, assistance from third party valuation specialists is typically obtained. The valuations are based on information available near the acquisition date and are based on expectations and assumptions that have been deemed reasonable by management. GOODWILL AND INTANGIBLES Goodwill represents the excess of cost over the fair market value of net assets acquired in business combinations. Indefinite-lived intangibles are comprised of trademarks. At September 30, 2008, goodwill and other indefinite-lived intangibles totaled $1.9 million, which arose from the acquisition of TerraVici Drilling Solutions. The Company reviews goodwill and other intangibles annually, during the fourth fiscal quarter, for impairment or more frequently if indicators of impairment warrant additional analysis. In order to test for impairment, goodwill acquired is assigned to reporting units that are expected to benefit from the synergies of the related business combination. The Company determines reporting units pursuant to SFAS No. 142. Goodwill is evaluated for impairment by first comparing management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of a reporting unit exceeds its fair value, a computation of the implied fair value of goodwill is compared with its related carrying value. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized. The Company’s acquisition-related intangible assets are comprised of non-compete agreements that are amortized over periods ranging from three to five years on a straight-line basis. 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 market values. The Company 77 primarily utilizes a cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts for moving funds into, and several ‘‘zero-balance’’ disbursement accounts for funding payroll and accounts payable. As a result of the Company’s cash management system, checks issued, but not presented to the banks for payment, may create negative book cash balances. Checks outstanding in excess of related book cash balances 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 The Company had restricted cash and cash equivalents of $13.3 million and $8.2 million at September 30, 2008 and 2007, respectively. Restricted cash is primarily for the purpose of potential insurance claims in the Company’s wholly-owned captive insurance company. Of the total at September 30, 2008, $2.0 million is from the initial capitalization of the captive and management has elected to restrict an additional $8.6 million. The remaining $2.7 million restricted cash consists of $0.7 million for indemnification on outstanding surety bonds and $2.0 million held in escrow in conjunction with the acquisition of TerraVici Drilling Solutions. The restricted amounts are primarily invested in short-term money market securities. The restricted cash and cash equivalents are reflected in the balance sheet as follows (in thousands): September 30, Other current assets Other assets 2008 $10,274 $ 3,012 2007 $6,203 $2,000 INVENTORIES AND SUPPLIES Inventories and supplies are primarily replacement parts and supplies held for use in the Company’s drilling operations. Inventories and supplies are valued at the lower of cost (moving average or actual) or market value. DRILLING REVENUES Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed. For certain contracts, the Company receives payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized on a straight line basis over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received by the Company for out-of-pocket expenses are recorded as revenues and direct costs. RENT REVENUES The Company enters into leases with tenants in its rental properties consisting primarily of retail and multi- tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings range from one to eleven years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants’ sales volume. Recoveries from 78 tenants for property taxes and operating expenses are recognized in other operating revenues in the Consolidated Statements of Income. The Company’s rent revenues are as follows: Years Ended September 30, Minimum rents Overage and percentage rents 2008 $9,469 $1,582 2007 (in thousands) $8,873 $1,474 2006 $8,538 $1,219 At September 30, 2008, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2009 2010 2011 2012 2013 Thereafter Total Amount $ 7,824 7,006 5,301 3,565 2,315 9,548 $35,559 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2008 and 2007, the cost and accumulated depreciation for real estate properties were as follows (in thousands): September 30, Real estate properties Accumulated depreciation 2008 2007 $60,811 (36,155) $24,656 $59,467 (33,886) $25,581 INVESTMENTS The Company maintains investments in equity securities of unaffiliated companies. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. The Company regularly reviews investment securities for impairment based on criteria that include the extent to which the investment’s carrying value exceeds its related market value, the duration of the market decline and the financial strength and specific prospects of the issuer of the security. Unrealized losses that are other than temporary are recognized in earnings. Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the Company recognizing its proportionate share of the income or loss of the investee. The Company currently 79 owns 8,000,000 shares of Atwood Oceanics, Inc. (Atwood) which represents approximately 12.5 percent of Atwood. The Company continues to account for Atwood on the equity method as the Company continues to have significant influence through its board of director seats. The quoted market value of the Company’s investment in Atwood was $291.2 million and $306.2 million at September 30, 2008 and 2007, respectively. Retained earnings at September 30, 2008 and 2007 includes approximately $60.5 million and $41.5 million, respectively, of undistributed earnings of Atwood. Summarized financial information of Atwood is as follows: September 30, Gross revenues Costs and expenses Net income Helmerich & Payne, Inc.’s equity in net income, net of income taxes Current assets Noncurrent assets Current liabilities Noncurrent liabilities Shareholders’ equity 2008 $526,604 311,166 $215,438 2007 (in thousands) $403,037 264,013 $139,024 2006 $276,625 190,503 $ 86,122 $ 17,366 $ 9,892 $ 7,268 $308,264 791,694 60,212 196,056 $843,690 $216,179 501,545 57,630 44,239 $615,855 $147,673 446,156 61,365 73,570 $458,894 Helmerich & Payne, Inc.’s investment $104,910 $ 74,210 $ 58,256 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 the Company’s assets and liabilities. The Company provides for uncertain tax positions when such tax positions do not meet the recognition thresholds or measurement standards prescribed by Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (FIN 48), which was adopted by the Company effective October 1, 2007, as more fully discussed in Note 3. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. The Company recognizes accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidation Statements of Income. SELF INSURANCE ACCRUALS The Company has accrued a liability for estimated worker’s compensation claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material. 80 EARNINGS PER SHARE Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per share includes the dilutive effect of stock options and restricted stock. STOCK-BASED COMPENSATION The Company records compensation expense associated with stock options in accordance with SFAS No. 123(R), ‘‘Share-Based Payment’’. The Company adopted the modified prospective transition method provided under SFAS No. 123(R) effective October 1, 2005. Under this transition method, compensation expense associated with stock options recognized in fiscal 2008, 2007 and 2006 includes: 1) expense related to the remaining unvested portion of all stock option awards granted prior to October 1, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123; and 2) expense related to all stock option awards granted subsequent to October 1, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Compensation expense related to the Company’s stock options is recorded as a component of general and administrative expenses in the Consolidated Statements of Income. TREASURY STOCK Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in-capital using the average-cost method. NEW ACCOUNTING STANDARDS In September 2006, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and will be adopted by the Company beginning in the first quarter of fiscal 2009. Although the Company will continue to evaluate the application of SFAS No. 157, management does not currently believe adoption will have a material impact on the Company’s financial condition or operating results. In February 2008, the FASB issued FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2). FSP 157-2 amends SFAS No. 157, Fair Value Measurements, to delay the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) and will be adopted by the Company beginning in the first quarter of fiscal 2010. In October 2008, the FASB issued FSP No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (FSP 157-3), to clarify the application of SFAS 157 in inactive markets for financial assets. FSP 157-3 became effective upon issuance. In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115 (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis and, with a few exceptions, is irrevocable and is applied only to entire 81 instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. At the effective date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. The Company, on October 1, 2008, does not plan to elect the fair value option for any existing eligible financial instruments or certain other items. In April 2008, the FASB issued FSP SFAS No. 142-3, Determining the Useful Life of Intangible Assets (FSP SFAS 142-3). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. This FSP is effective for fiscal years beginning after December 15, 2008, and interim periods within those years. This FSP must be applied prospectively to intangible assets acquired after the effective date. Accordingly, the Company will adopt FSP SFAS 142-3 in fiscal year 2010. In June 2008, FASB issued Staff Position (FSP) EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, to clarify that all outstanding unvested share- based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method pursuant to SFAS No. 128, Earnings per Share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and is to be applied retrospectively. The Company is currently evaluating FSP EITF 03-6-1 to determine the impact, if any, on the Consolidated Financial Statements. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51. Both of these standards are effective for financial statements issued for fiscal years beginning after December 15, 2008. SFAS No. 141(R) will be applied prospectively to business combinations occurring after the effective date. Earlier application is prohibited. The Company is currently evaluating the potential impact of adopting SFAS No. 160 but does not expect its adoption to have a significant impact on the Consolidated Financial Statements. In June 2007, the FASB ratified EITF Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). EITF 06-11 requires that the income tax benefits received on dividends or dividend equivalents paid to employees holding equity-classified shares be recorded as additional paid-in capital when the dividends or dividend equivalents are charged to retained earnings pursuant to SFAS No. 123(R). This EITF is applied prospectively and is effective for fiscal years beginning after December 15, 2007, and interim periods within those years. EITF 06-11 also requires the disclosure of any change in accounting policy for income tax benefits of dividends or dividend equivalents on share-based payment awards as a result of adoption. The Company will adopt EITF 06-11 beginning in the first quarter of fiscal 2009 and does not expect its adoption to have a significant impact on the Consolidated Financial Statements. 82 NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 2008 and 2007, the Company had $475 million and $445 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table (in thousands): Maturity Date Interest Rate 2008 2007 September 30, Fixed-rate debt: August 15, 2009 August 15, 2012 August 15, 2014 Senior credit facility: December 18, 2011 Less long-term debt due within one year Long-term debt 5.91% 6.46% 6.56% 2.84%-4.06% $ 25,000 75,000 75,000 325,000 500,000 25,000 $475,000 $ 25,000 75,000 75,000 270,000 445,000 — $445,000 The terms of the fixed-rate debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. The debt is held by various entities, including $8 million held by a company affiliated with one of the Company’s Board members. The Company has an agreement with a multi-bank syndicate for a $400 million senior unsecured credit facility. While the Company has the option to borrow at the prime rate for maturities of less than 30 days, the Company anticipates that the majority of all the borrowings over the life of the facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). The Company pays a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of the Company’s total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. At September 30, 2008, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. Financial covenants in the facility require the Company to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The facility contains additional terms, conditions, and restrictions that the Company believes are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2008, the Company had three letters of credit totaling $25.9 million under the facility and had borrowed $325 million against the facility with $49.1 million left available to borrow. The advances bear interest ranging from 2.84 percent to 4.06 percent. Subsequent to September 30, 2008, the outstanding balance was reduced by $35 million. At September 30, 2008, the Company was in compliance with all debt covenants. The Company also has an agreement with a single bank for an unsecured line of credit for $5 million. Pricing on the line of credit is prime minus 1.75 percent. The covenants and other terms and conditions are similar to the aforementioned senior credit facility except that there is no commitment fee. At September 30, 2008, the Company had no outstanding borrowings against this line. 83 At September 30, 2008, the Company had unsecured letters of credit totaling $6.3 million and a $0.7 million secured letter of credit both of which were used to obtain surety bonds for the international operations. As of September 30, 2008, the Company had an outstanding secured note payable to a bank totaling $1.7 million denominated in a foreign currency. The interest rate of the note was 16 percent with a one year maturity. The note and interest were paid in full subsequent to September 30, 2008. The Company has initiated discussions with lenders to obtain an additional credit facility. The Company anticipates the amount of the facility to range from $100 million to $150 million and does not expect significant difficulties in obtaining additional financing. However, because of the current conditions of the credit markets there can be no assurance that any new financing will be on equal or better terms than those of the current debt agreement. NOTE 3 INCOME TAXES The components of the provision for income taxes are as follows: Years Ended September 30, 2008 Current: Federal Foreign State Deferred: Federal Foreign State Total provision $ 97,871 28,875 10,813 137,559 110,077 (1,467) 9,388 117,998 $255,557 2007 (in thousands) $125,169 31,552 11,969 168,690 74,389 1,528 6,377 82,294 2006 $136,370 4,304 10,213 150,887 10,252 (7,776) 1,028 3,504 $250,984 $154,391 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 2008 $627,344 72,585 $699,929 2007 (in thousands) $579,589 110,764 $690,353 2006 $389,595 51,386 $440,981 84 Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets assumes, based on estimates and assumptions, that the Company will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances will be recorded against the deferred tax assets resulting in additional income tax expense in the future. The components of the Company’s net deferred tax liabilities are as follows: September 30, Deferred tax liabilities: Property, plant and equipment Available-for-sale securities Equity investments Other Total deferred tax liabilities Deferred tax assets: Pension reserves Self-insurance reserves Net operating loss and foreign tax credit carryforwards Financial accruals Other Total deferred tax assets Valuation allowance Net deferred tax assets Net deferred tax liabilities 2008 2007 (in thousands) $440,081 26,029 37,079 557 503,746 4,187 4,509 43,495 32,901 4,124 89,216 43,495 45,721 $303,915 46,501 25,413 1,415 377,244 1,689 2,884 26,926 21,995 6 53,500 28,231 25,269 $458,025 $351,975 Reclassifications have been made to the fiscal 2007 balances for certain components of deferred tax assets and liabilities in order to conform to the current year’s presentation. The change in the Company’s net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2008, the Company had foreign net operating loss carryforwards for income tax purposes of $2.1 million, and foreign tax credit carryforwards of approximately $42.9 million which will expire in years 2010 through 2018. The valuation allowance is primarily attributable to foreign net operating loss carryforwards and foreign tax credit carryforwards for which it is more likely than not that these will not be utilized. 85 Effective income tax rates as compared to the U.S Federal income tax rate are as follows: Years Ended September 30, 2008 2007 2006 U.S. Federal income tax rate Effect of foreign taxes State income taxes Effective income tax rate 35% — 2 37% 35% (1) 2 36% 35% (1) 1 35% In July 2006, the FASB Issued FIN 48, which clarifies the accounting for uncertainty in income tax recognized in an entity’s financial statements in accordance with FASB statement No. 109, Accounting for Income Taxes, and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a tax return. Under FIN 48, the impact of an uncertain income tax position must be recognized in the financial statements at the largest amount that is more likely than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has less than a 50 percent likelihood of being sustained. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted the provisions of FIN 48 effective October 1, 2007. The cumulative effect of adopting FIN 48 resulted in a decrease of approximately $5.0 million in retained earnings. The Company recognizes 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, 2008 and October 1, 2007, the Company had accrued interest and penalties of $2.5 million and $2.0 million, respectively. A reconciliation of the change in the Company’s gross unrecognized tax benefits for the fiscal year ended September 30, 2008, is as follows (in thousands): Unrecognized tax benefits at October 1, 2007 Gross increases—current period effect of tax positions Unrecognized tax benefits at September 30, 2008 $4,628 1,064 $5,692 As of September 30, 2008 and October 1, 2007, the Company’s liability for unrecognized tax benefits was $5.7 million and $4.6 million, respectively, which if recognized would affect the effective tax rate. The increase in unrecognized tax benefits was mainly due to the current period impact of tax positions taken in prior periods. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in the Company’s Consolidated Balance Sheets. The Company files 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 2004 through 2007. Audits in foreign jurisdictions are generally complete through fiscal year 2001. 86 It is reasonably possible that the amount of the unrecognized tax benefit with respect to certain unrecognized tax positions will increase or decrease during the next 12 months. However, the Company does not expect the change to have a material effect on results of operations or financial position. NOTE 4 SHAREHOLDERS’ EQUITY On September 30, 2008, the Company had 105,222,421 outstanding common stock purchase rights (‘‘Rights’’) pursuant to the terms of the Rights Agreement dated January 8, 1996, as amended by Amendment No. 1 dated December 8, 2005. As adjusted for the two-for-one stock splits in fiscals 1998 and 2006, and as long as the Rights are not separately transferable, one-half Right attaches to each share of the Company’s common stock. Under the terms of the Rights Agreement each Right entitles the holder thereof to purchase from the Company one full unit consisting of one one-thousandth of a share of Series A Junior Participating Preferred Stock (‘‘Preferred Stock’’), without par value, at a price of $250 per unit. The exercise price and the number of units of Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be attached to the common stock certificates and are not exercisable or transferable apart from the common stock, until ten business days after a person acquires 15 percent or more of the outstanding common stock or ten business days following the commencement of a tender offer or exchange offer that would result in a person owning 15 percent or more of the outstanding common stock. In the event the Company is acquired in a merger or certain other business combination transactions (including one in which the Company is the surviving corporation), or more than 50 percent of the Company’s assets or earning power is sold or transferred, each holder of a Right shall have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the exercise price of the Right. The Rights are redeemable under certain circumstances at $0.01 per Right and will expire, unless earlier redeemed, on January 31, 2016. NOTE 5 STOCK-BASED COMPENSATION The Company has one plan providing for common-stock based awards to employees and to non-employee Directors. The plan permits the granting of various types of awards including stock options and restricted stock awards. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire ten years after the grant date. The Company has the right to satisfy option exercises from treasury shares and from authorized but unissued shares. A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense and cash received from the exercise of stock options in fiscal 2008, 2007 and 2006 is as follows (in thousands, except per share amounts): September 30, Compensation expense Stock options Restricted stock 2008 2007 2006 $5,643 1,367 $7,010 $8,714 1,038 $9,752 $6,210 1,246 $7,456 87 Benefits of tax deductions in excess of recognized compensation cost of $24.9 million, $1.5 million and $10.2 million are reported as a financing cash flow in the Consolidated Statements of Cash Flow for fiscal 2008, 2007 and 2006 respectively. In December 2005, the Company accelerated the vesting of share options held by a senior executive who retired. As a result of that modification, the Company recognized additional compensation expense of $2.8 million for the fiscal year ended September 30, 2006 that is included in the table above. STOCK OPTIONS Vesting requirements for stock options are determined by the Human Resources Committee of the Company’s Board of Directors. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years. The Company uses 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 following summarizes the weighted-average assumptions in the model. Risk-free interest rate Expected stock volatility Dividend yield Expected term (in years) 2008 3.3% 31.1% .5% 4.8 2007 4.6% 35.9% .7% 5.5 2006 4.5% 36.9% .5% 5.2 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 the Company’s stock based upon historical experience over a period which approximates the expected term of the option. Expected Dividend Yield. The dividend yield is based on the Company’s current dividend yield. Expected Term. The expected term of the options granted represents the period of time that they are expected to be outstanding. The Company estimates the expected term of options granted based on historical experience with grants and exercises. 88 The following summary reflects the stock option activity for the Company’s common stock and related information for 2008, 2007, and 2006 (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant 2008 2007 2006 Weighted-Average Exercise Price $15.80 35.11 11.87 27.31 $20.02 $15.07 Options 6,032 742 (1,845) (110) 4,819 3,206 2,549 Weighted-Average Exercise Price $14.24 26.90 12.77 28.57 $15.80 $12.70 Options 5,619 731 (298) (20) 6,032 4,335 3,221 Weighted-Average Exercise Price $12.29 29.68 12.25 18.56 $14.24 $11.74 Options 6,488 640 (1,483) (26) 5,619 3,847 4,000 The following table summarizes information about stock options at September 30, 2008 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices $6.3975 to $9.4178 $11.3318 to $16.0100 $26.8950 to $35.1050 $6.3975 to $35.1050 Options 257 2,688 1,874 4,819 Weighted-Average Remaining Life Weighted-Average Exercise Price 1.2 4.4 8.3 5.7 $ 9.39 $13.42 $30.94 $20.02 Options 257 2,520 429 3,206 Weighted-Average Exercise Price $ 9.39 $13.25 $29.19 $15.07 At September 30, 2008, the weighted-average remaining life of exercisable stock options was 4.5 years and the aggregate intrinsic value was $90.2 million with a weighted-average exercise price of $15.07 per share. The number of options vested or expected to vest at September 30, 2008 was 4,800,379 with an aggregate intrinsic value of $111.5 million and a weighted-average exercise price of $19.97 per share. As of September 30, 2008, the unrecognized compensation cost related to the stock options was $11.7 million. That cost is expected to be recognized over a weighted-average period of 2.5 years. The weighted-average fair value of options granted during 2008, 2007 and 2006 was $10.81, $10.36 and $11.40, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006 was $21.9 million, $5.8, and $34.9 million, respectively. The grant date fair value of shares vested during 2008, 2007 and 2006 was $5.8 million, $5.4 million and $9.1 million, respectively. RESTRICTED STOCK Restricted stock awards consist of the Company’s common stock and are time vested over three to five years. The Company recognizes compensation expense on a straight-line basis over the vesting period. The 89 fair value of restricted stock awards is determined based on the closing price of the Company’s shares on the grant date. As of September 30, 2008, there was $3.6 million of total unrecognized compensation cost related to unvested restricted stock options. That cost is expected to be recognized over a weighted-average period of 2.5 years. Prior to the adoption of SFAS 123(R), unearned compensation related to restricted stock awards was classified as a separate component of shareholders’ equity. In accordance with the provisions of SFAS 123(R), on October 1, 2005, the balance in unearned compensation was reclassified to additional paid-in capital on the balance sheet. A summary of the status of the Company’s restricted stock awards as of September 30, 2008, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2008, 2007 and 2006 is as follows (share amounts in thousands): 2008 Weighted-Average Grant Date Fair Value per Share $29.27 35.11 16.01 30.24 2007 Weighted-Average Grant Date Fair Value per Share $29.57 26.90 — — Shares 213 27 — — 2006 Weighted-Average Grant Date Fair Value per Share $16.01 30.24 — — Shares 10 203 — — $29.92 240 $29.27 213 $29.57 Outstanding at October 1, Granted Vested Forfeited/Expired Outstanding on September 30, Shares 240 22 (3) (16) 243 NOTE 6 EARNINGS PER SHARE The computation of basic earnings per share is based on the weighted average number of common shares outstanding during the period. The computation of diluted earnings per share reflects the potential dilution that would occur if stock options were exercised and the dilution from the issuance of restricted shares, computed using the treasury stock method. A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: Basic weighted-average shares Effect of dilutive shares: Stock options and restricted stock Diluted weighted-average shares 2008 104,284 2,140 106,424 2007 (in thousands) 103,338 1,790 105,128 2006 104,658 1,433 106,091 At September 30, 2008, all options were included in the computation of diluted earnings per share. 90 At September 30, 2007, options to purchase 593,950 shares of common stock at a weighted-average price of $30.2375 were outstanding, but were not included in the computation of diluted earnings per share. Inclusion of these shares would be antidilutive. At September 30, 2006, options to purchase 809,450 shares of common stock at a weighted-average price of $30.2375 were outstanding, but were not included in the computation of diluted earnings per share. Inclusion of these shares would be antidilutive. NOTE 7 FINANCIAL INSTRUMENTS The Company had $175 million of fixed-rate long-term debt outstanding at September 30, 2008, which had an estimated fair value of $198 million. The debt was valued based on the prices of similar securities with similar terms and credit ratings. The Company used the expertise of an outside investment banking firm to assist with the estimate of the fair value of the long-term debt. The Company’s line of credit bears interest at market rates and the cost of borrowings, if any, would approximate fair value. The estimated fair value of the Company’s available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1), investments in limited partnerships carried at cost and assets held in a Non-qualified Supplemental Savings Plan: Equity Securities: September 30, 2008 September 30, 2007 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (in thousands) $ 7,685 $11,329 $ 67,867 $117,646 $— $— $ 75,552 $128,975 On an on-going basis, the Company evaluates the marketable equity securities to determine if a decline in fair market is other-than-temporary. If a decline in fair market value is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis established. In determining if an unrealized loss is other than temporary, the Company considers how long the market value of the investment has been below cost, how significant the decline in value is as a percentage of the original cost and the market in general and analyst recommendations. During the years ended September 30, 2008, 2007, and 2006, marketable equity available-for-sale securities with a fair value at the date of sale of $25.5 million, $73.4 million, and $28.2 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $22.0 million, $65.5 million, and $19.8 million, respectively. The investments in the limited partnerships carried at cost were approximately $12.4 million at September 30, 2008 and 2007. The estimated fair value of the limited partnerships was $17.3 million and $22.3 million at September 30, 2008 and 2007, respectively. The estimated fair value exceeded the cost of investments at September 30, 2008 and 2007 and, as such, the investments were not impaired. 91 The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $6.4 million and $7.8 million at September 30, 2008 and 2007, 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. During fiscal 2007, the Company liquidated its position in auction rate securities with no realized gains or losses. The proceeds of $48.3 million were included in the sale of investments under investing activities on the Consolidated Statements of Cash Flows. There were no purchases or sales of auction rate securities during fiscal 2008. The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2008 and 2007. NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of other comprehensive income for the years ended September 30, 2008, 2007 and 2006 were as follows (in thousands): Years Ended September 30, 2008 2007 2006 Unrealized appreciation (depreciation) on securities net of tax of $(10,558), $23,076 and $18,331 $(17,227) $ 37,654 $ 29,909 Reclassification of realized gains in net income net of tax of $8,358, $24,874 and $7,548 (13,636) (40,584) (12,318) Minimum pension liability adjustments net of tax of $5,621 and $2,765 Amortization of net periodic benefit costs – net of actuarial gain, net of tax of $(4,054) — 9,170 4,510 (6,615) $(37,478) — $ 6,240 — $ 22,101 The components of accumulated other comprehensive income (loss) at September 30, 2008 and 2007, net of applicable tax effects, were as follows (in thousands): September 30, Unrealized appreciation on securities Unrecognized actuarial gain (loss) and prior service cost 2008 $42,078 (3,671) $38,407 2007 $72,941 2,944 $75,885 92 NOTE 9 ACQUISITION OF TERRAVICI DRILLING SOLUTIONS On May 21, 2008, the Company acquired a private limited partnership, TerraVici Drilling Solutions (TerraVici) in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets acquired and liabilities assumed of TerraVici are recorded as of the acquisition date, at their respective fair values, and consolidated with those of the Company. TerraVici’s results of operations are included in the Company’s consolidated financial statements from the date of acquisition. TerraVici is included with all other non-reportable business segments. The Company paid $12.2 million to acquire TerraVici and it is now a wholly-owned subsidiary of the Company. The total purchase price included acquisition-related costs of $1.2 million. The terms of the transaction provide for future contingency payments up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met. TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. The Company acquired TerraVici to complement technology currently used with the FlexRig. By combining this new technology with the Company’s existing capabilities, the Company expects to improve drilling productivity and reduce total well cost to the customer. The acquisition was accounted for using the purchase method of accounting and the purchase price allocation resulted in the following amounts being allocated to the assets acquired and liabilities assumed at the acquisition date based upon their respective fair values. Current assets Fixed assets Trademark In-process research and development Other noncurrent assets Assets acquired Liabilities assumed Net assets acquired Goodwill Acquisition cost May 21, 2008 Amounts in thousands $ 371 4,257 919 11,129 280 16,956 (5,477) 11,479 702 $12,181 The fair value of the acquired intangible assets consists primarily of indefinite-lived trademarks of $0.9 million and non-compete agreements of $0.3 million. The weighted average amortization period for the non-compete agreements is 4.0 years. In-process research and development, or IPR&D, represents rotary steerable system (RSS) tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. Accordingly, the purchase price allocated to IPR&D was expensed 93 immediately subsequent to the acquisition. This charge will be amortized over 15 years for tax purposes. The $11.1 million estimated fair value of IPR&D was derived using the multi-period excess-earnings method. Pro forma summary financial results for the fiscal year ended September 30, 2008 are not presented because the consolidated results of operations, assuming the acquisition of TerraVici had occurred at the beginning of the reporting period, is not materially different from the Consolidated Statement of Income as reported. The excess of purchase price over the fair value assigned to the assets acquired and liabilities assumed represents the goodwill resulting from the acquisition. The amount allocated to goodwill is preliminary and subject to change, depending on the results of the final purchase price allocation. The Company does not expect any portion of this goodwill to be deductible for tax purposes. The goodwill attributable to the Company’s acquisition of TerraVici has been recorded as a noncurrent asset in the Company’s September 30, 2008 Consolidated Balance Sheet and will not be amortized. The allocation of the purchase price is subject to finalization of the Company’s management analysis of the fair value of the assets acquired and liabilities assumed of TerraVici as of the acquisition date. The final allocation of the purchase price may result in additional adjustments to the recorded amounts of asset and liabilities and may also result in adjustments to depreciation, amortization and acquired in-process research and development. The final allocation is expected to be completed as soon as practicable but no later than 12 months after the acquisition date. NOTE 10 EMPLOYEE BENEFIT PLANS The Company maintains a noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, the Company revised the Helmerich & Payne, Inc. Employee Retirement Plan (‘‘Pension Plan’’) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were discontinued and the Pension Plan was frozen. On September 30, 2007, the Company adopted the provisions of SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans’’ (‘‘SFAS 158’’). This statement requires employers to a) recognize the funded status of a benefit plan, determined as the difference between the fair value of plan assets and the benefit obligation, as an asset or liability in the statement of financial position, b) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, c) measure the defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end, which the Company has used historically, and d) include additional disclosures in the notes to the financial statements about effects on net periodic benefit cost that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations. 94 The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of assets over the two-year period ended September 30, 2008 and a statement of the funded status as of September 30, 2008 and 2007 (in thousands): Accumulated Benefit Obligation (‘‘ABO’’) Changes in Projected Benefit Obligations (‘‘PBO’’) Projected benefit obligation at beginning of year Service cost Interest cost Actuarial gain Benefits paid Projected benefit obligation at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return on plan assets Employer contribution Benefits paid Fair value of plan assets at end of year Funded status of the plan at end of year 2008 $ 69,475 $ 78,247 — 4,919 (8,975) (4,716) $ 69,475 $ 74,877 (13,662) 3,106 (4,716) $ 59,605 $ (9,870) 2007 $78,247 $87,669 — 4,865 (9,980) (4,307) $78,247 $66,752 9,782 2,650 (4,307) $74,877 $ (3,370) September 30, Amounts Recognized in the Consolidated Balance Sheets (in thousands): 2008 2007 Current pension liability Noncurrent pension liability Net amount recognized The Amounts Recognized in Accumulated Other Comprehensive Income at September 30, 2008 and 2007, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial gain (loss) Prior service cost Total $ (43) (9,827) $(9,870) $(5,919) (1) $(5,920) $ (35) (3,335) $(3,370) $ 4,749 (1) $ 4,748 The amount recognized in accumulated other comprehensive income and not yet reflected in periodic benefit cost expected to be amortized in next year’s periodic benefit cost is a net actuarial gain of $201. The weighted average assumptions used for the pension calculations were as follows: Years Ended September 30, Discount rate for net periodic benefit costs Discount rate for year-end obligations Expected return on plan assets Rate of compensation increase 2008 6.25% 7.25% 8.00% —% 2007 5.75% 6.25% 8.00% —% 2006 5.75% 5.75% 8.00% 5.00% The Company does not anticipate that funding the Pension Plan in fiscal 2009 will be required. However, the Company can choose to make discretionary contributions to fund distributions in lieu of liquidating pension 95 assets. During 2008, the Company elected to fund $3.1 million. The Company estimates contributing at least $5.0 million in fiscal 2009. However, due to the decline in the fair value of pension plan assets during 2008 and the current adverse conditions in the equity, debt and global markets, it is possible that contributions will be greater than expected. Components of the net periodic benefit expense (benefit) were as follows (in thousands): Years Ended September 30, Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Net pension expense (benefit) 2008 $ — 4,919 (5,990) — 9 $(1,062) 2007 $ — 4,865 (5,123) — 139 $ (119) 2006 $ 4,713 4,841 (4,936) (1) 876 $ 5,493 The Pension Plan was frozen and benefit accruals were discontinued effective September 30, 2006, thus reducing the service cost of the Plan. The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter (in thousands). 2009 $3,488 2010 $3,635 2011 $3,818 2012 $4,202 2013 $4,484 2014-2018 $24,254 Total $43,881 Years Ended September 30, Included in the Pension Plan is an unfunded supplemental executive retirement plan. INVESTMENT STRATEGY AND ASSET ALLOCATION The Company’s investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Plan while providing adequate security to meet the benefits promised under the Plan. The Company maintains a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any one investment. In determining the appropriate asset mix, the Company’s financial strength and ability to fund potential shortfalls are considered. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the Plans’ investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes. 96 The target allocation for 2009 and the asset allocation for the domestic Pension Plan at the end of fiscal 2008 and 2007, 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, 2009 56% 14 25 5 100% 2008 58% 15 24 3 100% 2007 61% 18 20 1 100% DEFINED CONTRIBUTION PLAN Substantially all employees on the United States payroll of the Company may elect to participate in the Company sponsored 401(k)/Thrift Plan by contributing a portion of their earnings. The Company contributes amounts equal to 100 percent of the first five percent of the participant’s compensation subject to certain limitations. Expensed Company contributions were $15.0 million, $10.9 million, and $8.4 million in 2008, 2007, and 2006, respectively. FOREIGN PLAN The Company maintains an unfunded pension plan in one of the international subsidiaries. Pension expense was approximately $0.4 million, $0.3 million and $0.4 million in 2008, 2007 and 2006, respectively. The pension liability at September 30, 2008 and 2007 was $5.0 million and $4.1 million, respectively. NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in the Company’s reserve for bad debt for 2008, 2007 and 2006: September 30, Reserve for bad debt: Balance at October 1, Provision for bad debt Write-off of bad debt Balance at September 30, 2008 $ 2,957 704 (2,330) $ 1,331 2007 (in thousands) $2,007 1,030 (80) $2,957 2006 $1,791 250 (34) $2,007 97 Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following: September 30, Accounts receivable, net of reserve: Trade receivables Income tax Insurance receivable Prepaid expenses and other: Prepaid value added tax Restricted cash Prepaid insurance Deferred mobilization Other Accrued liabilities: 2008 2007 (in thousands) $446,846 15,987 — $462,833 $337,829 — 1,990 $339,819 $ 6,146 $ 4,914 10,274 9,957 13,853 11,034 6,203 4,685 6,202 6,870 $ 51,264 $ 28,874 Taxes payable, other than income tax $ 42,884 $ 31,610 Accrued income taxes Self-insurance liabilities Payroll and employee benefits Accrued operating costs Other NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2008 Cash payments: Interest paid, net of amounts capitalized Income taxes paid $ 18,595 $133,194 — 3,696 44,525 16,500 20,768 10,033 2,406 36,010 5,185 16,812 $128,373 $102,056 2007 (in thousands) $ 9,713 $181,591 2006 $ 6,644 $109,857 Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2008, 2007 and 2006, does not include additions which have been incurred but not paid for as of the end of the 98 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 2008 $745,538 26,954 2007 (in thousands) $825,448 95,720 2006 $614,274 10,351 year (66,857) (26,954) (95,720) Capital expenditures per Consolidated Statements of Cash Flows $705,635 $894,214 $528,905 NOTE 13 RISK FACTORS CONCENTRATION OF CREDIT Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments, short-term investments and trade receivables. The Company places temporary cash investments in the U.S. with established financial institutions and invests in a diversified portfolio of highly rated, short-term money market instruments. In Venezuela, the Company had $43.4 million in cash at September 30, 2008, as discussed below in International Drilling Operations. The Company’s trade receivables, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of the Company’s international sales, however, are to large international or government-owned national oil companies. The Company performs ongoing credit evaluations of customers and does not typically require collateral in support for trade receivables. The Company provides an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on management’s knowledge of customer accounts. No significant credit losses have been experienced by the Company in recent history. VOLATILITY OF MARKET The Company’s operations can be materially affected by oil and gas prices. Recently, oil and natural gas prices have been volatile and have declined substantially. 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, along with the difficulty in predicting future prices can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The recent deterioration in the credit and capital markets could 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 99 spending and the demand for drilling services. This reduction in spending could have a material adverse effect on the Company’s operations. SELF-INSURANCE The Company self-insures a significant portion of expected losses relating to worker’s compensation, general, and automobile liability. Insurance coverage has been purchased for individual claims that exceed $1 million or $2 million, depending on whether a claim occurs inside or outside of the United States. The Company maintains certain other insurance coverage with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce the Company’s exposure to catastrophic events. The Company records estimates for incurred outstanding liabilities for worker’s compensation, general liability claims and for claims that are incurred but not reported. Estimates are based on historic experience and statistical methods that the Company believes are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. The Company has a wholly-owned captive insurance company, White Eagle Assurance Company (White Eagle), to provide a portion of the Company’s property damage insurance for company-owned drilling rigs and to reinsure international casualty deductibles. Rig property insurance coverage for ‘‘named wind storm’’ perils has been limited for the past few years. The Company purchased an aggregate limit of $100 million of ‘‘named wind storm’’ coverage and self-insures 10 percent of that limit as well as a $3.5 million deductible. For other insured perils, the Company insures rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. The Company self-insures 10 percent of the value for offshore rig property and 30 percent of the value for land rig property. The Company also self-insures a $1.0 million per occurrence deductible. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, the Company is generally entitled to indemnification under its drilling contracts from this risk. Premiums paid to White Eagle by the drilling segments have been included in the drilling segment expenses but eliminated, along with the premium earned income, in the Consolidated Statements of Income. INTERNATIONAL DRILLING OPERATIONS International drilling operations are a significant contributor to the Company’s revenues and net operating income. There can be no assurance that the Company will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on the Company’s financial position, results of operations, and cash flows. Also, the success of the Company’s international operations will be subject to numerous contingencies, some of which are beyond management’s control. These contingencies include general and regional economic conditions, fluctuations in currency exchange rates, changes in international regulatory requirements and international employment issues, and the burden of complying with foreign laws. On January 1, 2008, the Venezuelan government changed the official currency from the bolivar to the bolivar fuerte (Bsf) (2150 bolivar equals 2.15 bolivar fuerte). The Company derives its revenue in Venezuela from Petroleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company. The Company is 100 exposed to risks of currency devaluation in Venezuela primarily as a result of Bsf receivable balances and Bsf cash balances. In Venezuela, approximately 60 percent of the Company’s billings to the Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 bolivares to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars. On October 1, 2003, in compliance with applicable regulations, the Company submitted a request to the Venezuelan government seeking permission to convert existing bolivar balances into U.S. dollars. In January 2004, the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars and the remittance of those U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S. based parent. The Company was able to remit $8.8 million of such dividends in January 2004. This was the first dividend remitted under the new regulation. On January 16, 2006, a dividend of $6.5 million was paid to the U.S. based parent. On August 18, 2006, the Company applied for a $9.3 million dividend. The Venezuelan government subsequently approved $7.2 million of this dividend and on March 6, 2007, the $7.2 million was paid to the U.S. based parent. These dividends reduced the Company’s exposure to currency devaluation in Venezuela. On July 22, 2008, the Company submitted applications with the Venezuelan government requesting the approval to convert bolivar fuerte cash balances to U.S. dollars. When and if the Company receives approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation. While the Company has been successful in obtaining government approval for conversion of bolivares to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then bolivar fuerte cash balances would increase and expose the Company to increased risk of devaluation. As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of Bsf receivable and cash balances. The exchange rate per U.S. dollar increased to 2150 bolivares (2.15 Bsf) during 2005 from 1920 bolivares at September 30, 2004. As a result of the 12 percent devaluation of the bolivar during fiscal 2005 (from September 2004 through August 2005), the Company experienced total devaluation losses of $0.6 million during that same period. Even though Venezuela continues to operate under the exchange controls in place and the Venezuelan Bsf exchange rate is fixed at 2.15 Bsf to one U.S. dollar, the exact amount and timing of devaluation is uncertain. At September 30, 2008, the Company had a $43.4 million cash balance denominated in Bsf included in the balance sheet and exposed to the risk of currency devaluation. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2009 balance sheet components are similar to fiscal 2008 and if a 10 percent to 30 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $7.0 million to $18.0 million. The Company has an agreement with the Venezuelan state petroleum company whereby a portion of the Company’s dollar-based invoices are paid in U.S. dollars. Were this agreement to end, the Company would revert to receiving these payments in Bsf and thus increase Bsf cash balances and exposure to devaluation. 101 The Venezuelan subsidiary has received notification from PDVSA that reimbursement of U.S. dollar invoices previously paid in Bsf will be made only when supporting documentation has been approved. The supporting documentation has been delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $46.3 million. The Company is unable to determine the timing of when payment will be received. Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in labor and/or material and supplies necessary to operate some or all of its Venezuelan drilling rigs, thereby causing an adverse effect on the Company. The Company derives its revenue in Venezuela from PDVSA. At September 30, 2008, the Company had a net receivable from PDVSA of $65.5 million of which $5.2 million was 90 days old or older. At November 1, 2008, such receivable balance had decreased to approximately $63.9 million, of which approximately $13.5 million was 90 days old or older. The Company continues to communicate with PDVSA regarding the settlement of the outstanding receivables. While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, the Company, at this time, has no reason to believe the amounts will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than that of other customers in international countries in which the Company has drilling operations. NOTE 14 COMMITMENTS AND CONTINGENCIES COMMITMENTS Since March 2005, the Company has entered into separate drilling contracts with 25 exploration and production customers to build and operate a total of 127 new FlexRigs. Subsequent to September 30, 2008, the Company announced that agreements had been reached with five of the 25 above mentioned exploration and production companies to operate an additional 13 new FlexRigs, bringing the total of the new rigs to 140. Eight of these 140 new rigs were contracted for work in International Land operations and the remaining 132 in U.S. Land operations. The construction of the 140 rigs is estimated to cost $2.2 billion, of which over 70 percent was spent by the end of fiscal 2008. During construction, rig construction cost is recorded in construction in progress and then transferred to contract drilling equipment when the rig is placed in the field for service. Equipment, parts and supplies are ordered in advance to promote efficient construction progress. At September 30, 2008, the Company had commitments outstanding of approximately $270.7 million for the purchase of drilling equipment. 102 LEASES In May 2003, the Company signed a six-year lease for approximately 114,000 square feet of office space near downtown Tulsa, Oklahoma. In May 2008, the Company extended the lease for an additional ten years and added approximately 21,000 square feet of office space. Leasehold improvements made at the inception of the original lease were capitalized and are being amortized over the initial lease term. Leasehold improvements for the additional square footage are being capitalized and will amortize over the extended lease term. Fiscal Year 2009 2010 2011 2012 Thereafter Total Amount (in thousands) $ 5,835 4,158 2,595 2,543 14,744 $29,875 Total rent expense was $4.2 million, $3.7 million and $3.1 million for 2008, 2007 and 2006, respectively. CONTINGENCIES In August 2007, the Company experienced a fire on U.S. Land Rig 178, a 1,500 horsepower FlexRig2, when the well it was drilling had a blowout. There were no serious personal injuries although the drilling rig was lost. The rig was insured at a value that approximated replacement cost. At September 30, 2007, the net book value of the rig was removed from property, plant and equipment and a receivable from insurance was recorded, net of a $1.0 million insurance deductible expensed. During fiscal 2008, gross insurance proceeds of approximately $8.7 million were received and a gain of approximately $5.0 million was recorded. The Company anticipates settling the insurance claim before the end of the first quarter of fiscal 2009 and expects to receive additional insurance proceeds of less than $0.3 million. In August 2005, the Company’s Rig 201, which operates on an operator’s tension-leg platform in the Gulf of Mexico, lost its entire derrick and suffered significant damage as a result of Hurricane Katrina. The rig was insured at a value that approximated replacement cost. Capital costs incurred in conjunction with rebuilding the rig were capitalized in fiscal 2007 and are being depreciated. Insurance proceeds received through fiscal 2007 totaled approximately $19.3 million with approximately $16.7 recorded as a gain from involuntary conversion of long-lived assets. During fiscal 2008, proceeds of approximately $5.2 million were received and recorded as a gain from involuntary conversion. Any future proceeds will be recorded as gain from involuntary conversion of long-lived assets when received. The Company expects to settle this claim early in fiscal 2009 and estimates additional proceeds of less than $0.3 million. Various legal actions, the majority of which arise in the ordinary course of business, are pending. The Company maintains insurance against certain business risks subject to certain deductibles. None of these legal actions are expected to have a material adverse effect on the Company’s financial condition, cash flows or results of operations. 103 The Company is contingently liable to sureties in respect of bonds issued by the sureties in connection with certain commitments entered into by the Company in the normal course of business. The Company has agreed to indemnify the sureties for any payments made by them in respect of such bonds. NOTE 15 SEGMENT INFORMATION The Company operates principally in the contract drilling industry. The Company’s contract drilling business includes the following reportable operating segments: U.S. Land, Offshore, and International Land. The contract drilling operations consist mainly of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company’s primary international areas of operation include Venezuela, Colombia, Ecuador and other South American countries. The International Land operations have similar services, have similar types of customers, operate in a consistent manner and have similar economic and regulatory characteristics. Therefore, the Company has aggregated its international operations into one reportable segment. Each reportable segment is a strategic business unit which is managed separately. Other includes non-reportable operating segments. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. The Company evaluates segment performance based on income or loss from operations (segment operating income) before income taxes which includes: revenues from external and internal customers (cid:129) (cid:129) direct operating costs (cid:129) depreciation and (cid:129) allocated general and administrative costs but excludes corporate costs for other depreciation, income from asset sales and other corporate income and expense. General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods which the Company believes to be a reasonable reflection of the utilization of services provided. Segment operating income for all segments is a non-GAAP financial measure of the Company’s performance, as it excludes general and administrative expenses, corporate depreciation, income from asset sales and other corporate income and expense. The Company considers segment operating income to be an important supplemental measure of operating performance for presenting trends in the Company’s core businesses. This measure is used by the Company to facilitate period-to-period comparisons in operating performance of the Company’s reportable segments in the aggregate by eliminating items that affect comparability between periods. The Company believes that segment operating income is useful to investors because it provides a means to evaluate the operating performance of the segments and the Company on an ongoing basis using criteria that are used by our internal decision makers. Additionally, it highlights operating trends and aids analytical comparisons. However, segment operating income has limitations and should not be used as an 104 alternative to operating income or loss, a performance measure determined in accordance with GAAP, as it excludes certain costs that may affect the Company’s operating performance in future periods. Due to the continued growth of the drilling segments over the past few years, the Company reevaluated its reportable segments. With the growth of the drilling segments, the Real Estate segment has become a smaller percentage of total segment operating income. In the evaluation of segment reporting, the Company determined that the total of external revenues reported by the three reportable operating segments, U.S. Land, Offshore and International Land, comprised more than 75 percent of total consolidated revenue. As a result, the Real Estate segment previously shown as a reportable segment has been included with all other non-reportable business segments. Revenues included in all other consist primarily of rental income. Financial information for fiscal 2007 and 2006 has been restated to reflect this change. 105 Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2008, 2007, and 2006 is shown in the following table: (in thousands) 2008 Contract Drilling U.S. Land Offshore International Land Other External Sales Inter- Segment Total Sales Segment Operating Income Depreciation Total Assets Additions to Long-Lived Assets $1,542,038 $ — $1,542,038 $605,718 $161,893 $2,660,232 $682,310 154,452 328,244 2,024,734 11,809 2,036,543 — — — 878 878 154,452 33,394 12,152 152,497 14,614 328,244 69,973 29,614 368,659 41,696 2,024,734 709,085 203,659 3,181,388 738,620 12,687 (7,996) 7,107 406,657 6,918 2,037,421 701,089 210,766 3,588,045 745,538 Eliminations — (878) (878) — — — — Total 2007 Contract Drilling U.S. Land Offshore International Land Other $2,036,543 $ — $2,036,543 $701,089 $210,766 $3,588,045 $745,538 $1,174,956 $ — $1,174,956 $467,000 $106,107 $2,073,015 $762,501 123,148 320,283 1,618,387 11,271 1,629,658 — — — 828 828 123,148 22,081 10,687 124,014 25,418 320,283 1,618,387 12,099 105,179 594,260 5,007 23,782 314,625 22,726 140,576 2,511,654 810,645 5,466 373,715 14,803 1,630,486 599,267 146,042 2,885,369 825,448 Eliminations — (828) (828) — — — — Total 2006 Contract Drilling U.S. Land Offshore International Land Other $1,629,658 $ — $1,629,658 $599,267 $146,042 $2,885,369 $825,448 $ 829,062 $ — $ 829,062 $351,255 $ 66,127 $1,356,817 $560,664 154,543 230,829 1,214,434 10,379 1,224,813 — — — 783 783 154,543 31,865 11,401 110,961 18,756 230,829 52,318 1,214,434 435,438 11,162 4,411 19,471 96,999 4,584 310,836 31,245 1,778,614 610,665 356,098 3,609 1,225,596 439,849 101,583 2,134,712 614,274 Eliminations — (783) (783) — — — — Total $1,224,813 $ — $1,224,813 $439,849 $101,583 $2,134,712 $614,274 106 The following table reconciles segment operating income to income before taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, Segment operating income Income from asset sales Gain from involuntary conversion of long-lived assets 2008 2007 2006 $ 701,089 $ 599,267 $ 439,849 13,490 10,236 41,697 16,661 7,492 — Corporate general and administrative costs and corporate depreciation (31,999) (25,306) (30,055) Operating income Other income (expense) Interest and dividend income Interest expense Gain on sale of investment securities Other Total unallocated amounts 692,816 632,319 417,286 5,038 (18,689) 21,994 (1,230) 7,113 4,234 (10,126) 65,458 (1,532) 58,034 9,834 (6,644) 19,866 639 23,695 Income before income taxes and equity in income of affiliate $ 699,929 $ 690,353 $ 440,981 The following table presents revenues from external customers and long-lived assets by country based on the location of service provided (in thousands). Years Ended September 30, 2008 2007 2006 Revenues United States Venezuela Ecuador Colombia Other Foreign Total Long-Lived Assets United States Venezuela Ecuador Colombia Other Foreign Total $1,687,075 $1,292,636 $ 972,021 167,172 127,278 55,100 42,439 84,757 93,903 26,849 88,992 84,594 88,709 17,748 61,741 $2,036,543 $1,629,658 $1,224,813 $2,461,726 $1,951,907 $1,284,235 76,867 25,560 41,889 76,209 83,804 45,120 10,061 61,724 83,160 42,859 9,793 63,087 $2,682,251 $2,152,616 $1,483,134 Long-lived assets are comprised of property, plant and equipment. Revenues from one company doing business with the contract drilling segment accounted for approximately 10.3 percent, 5.5 percent, and 4.2 percent of the total operating revenues during the years ended September 30, 2008, 2007, and 2006, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.5 percent, 10.8 percent, and 11.2 percent of total operating revenues during the years ended September 30, 2008, 2007 and 2006, respectively. Collectively, 107 the receivables from these customers were approximately $59.4 million and $49.0 million at September 30, 2008 and 2007, respectively. NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 2008 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (in thousands, except per share amounts) Operating revenues Operating income Net income Basic net income per common share Diluted net income per common share $456,663 $473,644 $522,517 $583,719 168,633 107,830 1.04 1.02 155,670 102,054 .98 .96 177,807 125,369 1.20 1.18 190,706 126,485 1.20 1.18 2007 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues Operating income Net income Basic net income per common share Diluted net income per common share $386,399 $372,536 $421,274 $449,449 146,654 110,786 1.07 1.06 164,284 106,861 1.04 1.02 154,672 115,204 1.11 1.09 166,709 116,410 1.13 1.10 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 2008, net income includes an after-tax gain from the involuntary conversion of long-lived assets of $3.1 million, $0.03 per share on a diluted basis. In the second quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $3.3 million, $0.03 per share on a diluted basis and an after-tax gain from the sale of assets of $1.2 million, $0.01 per share on a diluted basis. In the third quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $10.0 million, $0.09 per share on a diluted basis, an after-tax gain from the sale of assets of $1.0 million, $0.01 per share on a diluted basis, and an after-tax gain from the involuntary conversion of long-lived assets of $3.5 million, $0.03 per share on a diluted basis. Included in net income for the third quarter of fiscal 2008 is an after-tax charge of $6.9 million, $0.07 per share on a diluted basis, from in-process research and development. In the fourth quarter of fiscal 2008, net income includes an after-tax gain from the sale of assets of $5.8 million, $0.05 per share on a diluted basis. Included in net income for the fourth quarter of fiscal 2008 is after-tax equipment abandonments of $7.3 million, $0.07 per share on a diluted basis. 108 In the first quarter of fiscal 2007, net income includes an after-tax gain on the sale of available-for-sale securities of $16.2 million, $0.15 per share on a diluted basis. In the second quarter of fiscal 2007, net income includes an after-tax gain from the sale of assets of $20.5 million, $0.20 per share on a diluted basis and an after-tax gain from the involuntary conversion of long-lived assets of $3.3 million, $0.03 per share on a diluted basis. In the third quarter of fiscal 2007, net income includes an after-tax gain on the sale of available-for-sale securities of $15.5 million, $0.15 per share on a diluted basis, an after-tax gain from the sale of assets of $3.9 million, $0.03 per share on a diluted basis, and an after-tax gain from the involuntary conversion of long-lived assets of $3.7 million, $0.03 per share on a diluted basis. In the fourth quarter of fiscal 2007, net income includes an after-tax gain on the sale of available-for-sale securities of $8.4 million, $0.08 per share on a diluted basis, an after-tax gain from the sale of assets of $1.9 million, $0.01 per share on a diluted basis, and an after-tax gain from the involuntary conversion of long-lived assets of $3.6 million, $0.04 per share on a diluted basis. Performance Graph The following performance graph reflects the yearly percentage change in the Company’s cumulative total stockholder return on common stock as compared with the cumulative total return 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. CUMULATIVE TOTAL RETURN ON COMMON STOCK $400 $350 $300 $250 $200 $150 $100 $50 $0 2003 2004 2005 2006 2007 2008 Helmerich & Payne, Inc. S&P 500 Index S&P 500 Oil & Gas Drilling Index 12DEC200809494097 109 Directors Officers W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer Douglas E. Fears Executive Vice President and Chief Financial Officer Steven R. Mackey Executive Vice President, Secretary, and General Counsel John W. Lindsay Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. M. Alan Orr Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. Gordon K. Helm Vice President and Controller W. H. Helmerich, III Chairman of the Board Tulsa, Oklahoma Hans Helmerich President and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong**(***) President Colorado Christian University Lakewood, Colorado Glenn A. Cox*(***) President and Chief Operating Officer, Retired Phillips Petroleum Company Bartlesville, Oklahoma Randy A. Foutch*(***) Chairman and Chief Executive Officer Laredo Petroleum, Inc. Tulsa, Oklahoma Paula Marshall**(***) Chief Executive Officer, The Bama Companies, Inc. Tulsa, Oklahoma Hon. Francis Rooney Chairman, 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 110 Stockholders’ Meeting The annual meeting of stockholders will be held on March 4, 2009. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 26, 2009. Stock Exchange Listing Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol ‘‘HP.’’ The newspaper abbreviation most commonly used for financial reporting is ‘‘HelmP.’’ Options on the Company’s stock are also traded on the New York Stock Exchange. Stock Transfer Agent and Registrar As of November 20, 2008, there were 675 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records. Our Transfer Agent is responsible for our shareholder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with The Transfer Agent at the following address: Computershare Trust Company, N.A. Investor Services P.O. Box 43078 Providence, RI 02940-3078 Telephone: (800) 884-4225 (781) 575-4706 Available Information Quarterly reports on Form 10-Q, earnings releases, and financial statements are made available in the Investor Relations section of the Company’s website. Also located on the Company’s website in the Corporate Governance section 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. Quarterly reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request. Annual CEO Certification The annual CEO Certification required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual was provided to the New York Stock Exchange on or about March 14, 2008. 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 26NOV200818032160 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 ANNUAL REPORT FOR 2008 

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